<PAGE> 1
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 August 31, 1996
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 October 11, 1996
- ---------------------------- -------------------------------
Common stock, $.20 par value 3,093,913
<PAGE> 2
COLUMBUS ENERGY CORP.
INDEX
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
August 31, 1996 and
November 30, 1995 3
Consolidated Statements of Income -
Three Months and Nine Months
Ended August 31, 1996 and 1995 5
Consolidated Statement of
Stockholders' Equity -
Nine Months Ended August 31, 1996 6
Consolidated Statements of Cash Flows -
Nine Months Ended August 31, 1996
and 1995 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 2-5. Not Applicable
Item 6. Exhibits and Reports
on Form 8-K 27
Signatures 28
</TABLE>
2
<PAGE> 3
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<S> <C>
August 31, November 30,
1996 1995
---------- ------------
(unaudited)
(in thousands)
Current assets:
Cash and cash equivalents $ 1,122 $ 1,414
Accounts receivable:
Joint interest partners 1,391 1,258
Oil and gas sales 1,346 817
Less allowance for doubtful accounts (116) (116)
Income tax receivable - 7
Deferred income taxes (Note 3) 96 1,290
Inventory of oil field equipment,
at lower of average cost or market 85 76
Other 126 78
-------- --------
Total current assets 4,050 4,824
-------- --------
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 27,769 22,244
Other property and equipment 2,006 2,028
-------- --------
29,775 24,272
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (12,845) (10,775)
-------- --------
Net property and equipment 16,930 13,497
-------- --------
$ 20,980 $ 18,321
======== ========
</TABLE>
(continued)
3
<PAGE> 4
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
August 31, November 30,
1996 1995
----------- ----------------
(unaudited)
(in thousands)
<S> <C> <C>
Current liabilities:
Accounts payable $ 1,145 $ 1,314
Undistributed oil and gas
production receipts 99 348
Accrued production and property taxes 889 635
Prepayments from joint interest owners 257 189
Accrued expenses 344 318
Income taxes payable 84 -
Other 11 79
--------- ---------
Total current liabilities 2,829 2,883
--------- ---------
Long-term bank debt (excluding current
maturities) (Note 2) 3,200 1,600
Deferred income taxes (Note 3) 261 652
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
3,461,260 in 1996, and 3,328,580 in 1995
(outstanding 3,086,691 in 1996 and
3,068,149 in 1995) 692 666
Additional paid-in capital 16,616 15,842
Retained earnings (accumulated
deficit), since December 1, 1987 161 (1,378)
--------- ---------
17,469 15,130
Less: Treasury stock at cost
374,569 shares in 1996 and
260,431 shares in 1995 (2,779) (1,944)
--------- ---------
Total stockholders' equity 14,690 13,186
--------- ---------
$ 20,980 $ 18,321
========== =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE> 5
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended Three Months Ended
August 31, August, 31,
------------------------ ----------------------
1996 1995 1996 1995
-------- -------- ----- ------
(in thousands, except per share data)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 7,745 $ 6,160 $ 2,514 $ 1,665
Operating and management
services 820 1,044 262 292
Interest and other income 271 123 36 42
------- ------- ------- -------
Total revenues 8,836 7,327 2,812 1,999
------- ------- ------- -------
Costs and expenses:
Lease operating expenses 1,477 1,411 502 458
Property and production taxes 757 590 253 178
Operating and management
services 648 802 231 258
General and administrative 783 1,006 242 228
Depreciation, depletion and
amortization 2,118 2,156 745 680
Impairment of long-lived
assets 165 - - -
Exploration expense 182 139 38 42
------- ------- ------- -------
Total costs and expenses 6,130 6,104 2,011 1,844
------- ------- ------- -------
Operating income 2,706 1,223 801 155
------- ------- ------- -------
Other expenses (income):
Interest 207 147 65 41
Retirement and separation - 141 - 35
Litigation (Note 4) 13 120 3 3
Other 4 7 (3) (4)
------- ------- ------- -------
224 415 65 75
------- ------- ------- -------
Earnings before
income taxes 2,482 808 736 80
Provision for income taxes
(Note 3) 943 307 280 30
------- ------- ------- -------
Net earnings $ 1,539 $ 501 $ 456 $ 50
======= ======= ======= =======
Earnings per share:
Primary $ .50 $ .16 $ .15 $ .02
======= ======= ======= =======
Fully diluted N/A N/A $ .14 N/A
=======
Average number of common
shares outstanding:
Primary 3,049 3,160 3,131 3,117
======= ======= ======= =======
Fully diluted N/A N/A 3,175 N/A
=======
</TABLE>
The accompanying notes are an integral part of these
financial statements.
5
<PAGE> 6
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Nine Months Ended August 31, 1996
(Unaudited)
<TABLE>
<CAPTION>
Retained
Common Stock Additional Earnings Treasury Stock
------------------- Paid-in (Accumulated) --------------------
Shares Amount Capital Deficit) Shares Amount
---------- ------- ---------- ------------ -------- ------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1995 3,328,580 $ 666 $15,842 $(1,378) 260,431 $(1,944)
Exercise of employee
stock options 122,778 24 691 - 43,800 (370)
Purchase of shares - - - - 86,100 (579)
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
Tax benefit of
disqualifying
disposition of
incentive stock
options - - 54 - - -
Net earnings - - - 1,539 - -
--------- ------ ------- ------- ------- -------
Balances,
August 31, 1996 3,461,260 $ 692 $16,616 $ 161 374,569 $(2,779)
========= ====== ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
6
<PAGE> 7
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended August 31,
-------------------------------
1996 1995
------------- --------------
(in thousands)
<S> <C> <C>
Net earnings $ 1,539 $ 501
Adjustments to reconcile net earnings
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization 2,118 2,156
Impairment of assets 165 -
Deferred income tax provision 856 251
Exploration expense, non-cash portion - 4
Gain on asset sale (175) -
Other 106 154
Changes in operating assets and
liabilities:
Accounts receivable (662) 266
Other current assets (50) (58)
Accounts payable (168) 583
Undistributed oil and gas production
receipts (249) (157)
Accrued production and property taxes 254 447
Accrued expenses 26 40
Prepayments from joint interest owners 68 (61)
Income taxes 91 (79)
Other current liabilities (68) (82)
-------- --------
(758) 899
-------- --------
Net cash provided by
operating activities 3,851 3,965
-------- --------
Cash flows from investing activities:
Additions to oil and gas properties (5,849) (3,609)
Additions to other assets (28) (66)
Proceeds from sale of Resources
common stock, net of cash - 4,071
Proceeds from sale of assets 336 33
-------- --------
Net cash from (used in)
investing activities $ (5,541) $ 429
-------- --------
</TABLE>
(continued)
7
<PAGE> 8
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (continued)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended August 31,
-----------------------------
1996 1995
------------ -------------
(in thousands)
<S> <C> <C>
Cash flows from financing activities:
Proceeds from long-term debt $ 3,200 $ 1,790
Reduction in long-term debt (1,600) (4,390)
Proceeds from issuance of
common stock 377 206
Purchase of treasury stock (579) (1,513)
Other - (2)
-------- --------
Net cash provided by (used in)
financing activities 1,398 (3,909)
Effect of exchange rate on cash - 8
-------- --------
Net increase (decrease) in cash and
cash equivalents (292) 493
Cash and cash equivalents at
beginning of period 1,414 1,819
-------- --------
Cash and cash equivalents at
end of period $ 1,122 $ 2,312
======== ========
Supplemental disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 184 $ 166
======== ========
Income taxes (refund) $ (4) $ 135
======== ========
Supplemental disclosure of non-cash
investing and financing activities:
Non-cash compensation expense
related to common stock $ 20 $ 153
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
8
<PAGE> 9
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
subsidiaries, CEC Resources Ltd. ("Resources") and Columbus Gas Services,
Inc.("CGSI"). Resources activity is only included through February 24, 1995
when it was divested by Columbus by a rights offering to its shareholders. All
significant intercompany balances have been eliminated in consolidation. The
term "Company" as used herein includes Columbus and its subsidiary or
previously owned subsidiaries.
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
CGSI. All of the Company's oil and gas reserves are located in the United
States with the majority of its production and proved reserves being natural
gas concentrated in South Texas and the Gulf Coast.
The consolidated financial statements of the Company have been
prepared in accordance with generally accepted accounting principles and
require the use of management's or consultant's estimates and assumptions. The
Company's most significant financial estimates are its remaining proved oil and
gas reserves at any point in time using the latest crude oil and natural gas
prices. 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 August 31, 1996
and November 30, 1995, the results of its operations and cash flows for the
three and nine months ended August 31, 1996 and 1995. 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 hedges to manage price
exposure. Realized gains and losses on hedges are recognized in oil and gas
sales as settlement occurs.
9
<PAGE> 10
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
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.
The average shares outstanding for 1995 and the per share earnings
have been restated retroactively for the 10% stock dividend paid to
shareholders of record on February 24, 1995. A total of 291,399 shares were
issued from treasury stock and $1,841 paid for fractional shares.
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. 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.
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 reserves of oil and gas, as estimated by petroleum engineers, on a field
by field 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. Depreciation of other assets are provided on
the straight line method over their estimated useful lives.
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
10
<PAGE> 11
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
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. When property pools are determined to be impaired,
an impairment loss equal to the difference between the carrying value and the
fair value of the pool is recognized in that period. After consideration of
risk, fair value is estimated as the present value of future net cash flows
over the economic life of the reserves. Future cash flows and fair value
estimates relating to SFAS 121 impairment are very sensitive to prices of oil
and gas utilized.
The Company follows the entitlements method of accounting for gas
balancing of gas production. The Company's gas imbalances are immaterial at
November 30, 1995 and August 31, 1996.
Other Property and Equipment
Gains and losses from retirement or replacement of other properties and
equipment are included in income. Betterments and renewals are capitalized.
Maintenance and repairs are charged to operating expense.
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 unless adopted earlier.
The Company has determined when it adopts this standard it will use the
alternative pro forma disclosures as provided.
(2) LONG-TERM DEBT
The Company has a credit agreement with Norwest Bank Denver, N.A. that was
executed in July 1992. The credit is collateralized by a first lien on oil and
gas properties.
As directed by the Company, the borrowing base until April 1, 1997 is
limited to $7,000,000, without regard to the maximum allowable amount that
would have been set by the bank during its annual redetermination. A fee of
.25% is required for any unused credit which is the difference between the
borrowing base and the outstanding borrowings.
11
<PAGE> 12
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
(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 those 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. Additional accumulated ownership changes
again exceeded 50% by August 25, 1993, thereby causing a second ownership
change to occur which has further limited the utilization of $593,000 of
post-1987 net operating losses until fiscal 1996 and subsequent years.
The Company has adopted Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes" ("SFAS 109"). 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. 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. Estimated
utilization of deferred tax assets is affected by oil and gas prices realized
in the current period and future periods as well as the success of drilling new
wells or developing undeveloped proved reserves.
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.
12
<PAGE> 13
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
The provision for income taxes consists of the following (in
thousands):
<TABLE>
<CAPTION>
Nine Months Ended August 31,
----------------------------
1996 1995
---- ----
<S> <C> <C>
Current:
Federal $ 50 $ 12
Foreign (Canada) - 29
State 37 15
------ ------
87 56
------ ------
Deferred:
Federal 856 207
Foreign (Canada) - 44
------ ------
856 251
------ ------
Total income tax expense $ 943 $ 307
====== ======
</TABLE>
The components of earnings before income taxes are (in thousands):
<TABLE>
<CAPTION>
Nine Months Ended Three Months Ended
August 31, August 31,
------------------- -------------------
1996 1995 1996 1995
------ ------ ------ ------
<S> <C> <C> <C> <C>
U.S. $2,482 $ 599 $ 736 $ 80
Canada - 209 - -
------ ------ ------ ------
Total $2,482 $ 808 $ 736 $ 80
====== ====== ====== ======
</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
----------------------------
Nine Months Ended August 31,
----------------------------
1996 1995
---- ----
<S> <C> <C>
U.S. Statutory rate 34% 34%
Foreign taxes (Canada) - 9
Foreign tax credit - (9)
State income taxes 2 2
Other 2 2
---- ----
38% 38%
==== ====
</TABLE>
13
<PAGE> 14
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
During the nine months of fiscal 1996, certain tax assets were utilized
as a result of the taxable income. 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
----------------------------------------------------
Stock-
Dec. 1, holders' Aug. 31,
1995 Equity Operations 1996
-------- -------- ---------- --------
<S> <C> <C> <C> <C>
Deferred tax assets:
Pre-1987 loss carryforwards $ 1,976 $ - $ (426) $ 1,550
Post-1987 loss carryforwards 720 - (540) 180
Percentage depletion
carryforwards 894 - - 894
State income tax loss
carryforwards 197 - (88) 109
Other 245 - (26) 219
-------- ------ ------- ------
Total 4,032 - (1,080) 2,952
Valuation allowance (1,737) - - (1,737)
-------- ------ ------- ------
Deferred tax assets 2,295 - (1,080) 1,215
-------- ------ ------- ------
Tax benefit of disqualifying
disposition of incentive
stock options - 54(a) (54) -
-------- ------ ------- ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (1,657) - 278 (1,379)
-------- ------ ------- ------
Net tax asset (liability) $ 638 $ 54 $ (856) $ (164)
======== ====== ======= ======
</TABLE>
- -----------------
(a) Credited to additional paid-in capital.
The Company has net operating loss carryforwards (in thousands) available
at November 30, 1995 as follows:
<TABLE>
<CAPTION>
Net
Expiration Year Operating loss
--------------- --------------
<S> <C>
1999 $ 4,517
2000 907
2001 386
2003 478
2004 115
2010 1,593
-------
$ 7,996
=======
</TABLE>
For U.S. Alternative Minimum Tax purposes the Company had net operating
loss carryforwards of $8,700,000 as of November 30, 1995. The Company also has
percentage depletion carryforwards of $2,350,000 which do not expire. State
income tax operating loss carryforwards of $2,900,000 were available at November
30, 1995.
14
<PAGE> 15
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(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 two separate swaps of 60,000 Mmbtu per month each
of natural gas for the period from April 1996 through November 1996 which volume
equated to about 55% of first quarter production. The first swap was at a
price of $1.74 per Mmbtu while the second swap was at a price of $1.88 per
Mmbtu. To partially protect against probable higher gas prices for October and
November 1996, the Company also purchased NYMEX call contracts for those two
months for 60,000 Mmbtu of natural gas at $1.805 and $1.875, respectively. The
October call contract was sold in June 1996 for $37,500 which partially offset
losses from the swaps for June. The November call contract was sold in
September 1996 for $4,500 which will partially offset losses from the swaps for
September.
Columbus also entered into a swap of crude oil prices by selling a strip of
10,000 barrels per month for the twelve month period from January 1996 through
December 1996 at an average daily price of $17.25 per barrel with an upside cap
of $19.50, thereby limiting the maximum possible reduction in revenue in any
month to $2.25 per barrel, or $22,500. The difference between the hedge price
and the actual daily closing price of the near month contract on the NYMEX has
been settled monthly utilizing that cap thus far in fiscal 1996. This contract
volume represents approximately 50% of recent monthly production.
Columbus recently entered into an additional swap of crude oil prices 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.
The natural gas and crude oil swaps described above are considered
financial instruments with off-balance sheet risk and were acquired in the
normal course of business to reduce exposure to downward movements in the price
of crude oil and natural gas. Such instruments can involve, to varying degrees,
elements of market and credit risk which exceed the amount recognized in the
balance sheet. As calculated as of October 10, 1996, the Company had natural gas
and crude oil swaps as follows:
15
<PAGE> 16
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
<TABLE>
<CAPTION>
Notional Market
Value Value
----------- -----------
<S> <C> <C>
Natural gas $ 651,600 $ 492,000
Crude oil (9/96-12/96) 690,000 600,000
Crude oil (11/96-10/97) 2,540,400 2,502,000
</TABLE>
The market value will change constantly during the remaining term of the
contracts and will result in a reduction or increase in sales reported by the
Company during that period. In particular, the new oil swap which contract
period begins November 1, 1996 has a market value which cannot yet be
determined and the above table is based upon current futures prices which can
fluctuate dramatically until then. These swaps are primarily seen as insurance
against significant downside price fluctuations since losses occurring when
future prices are above the swap level are mitigated somewhat by the higher
prices actually received in the field for the equivalent volumes.
(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 $82,000 and $81,000 for the
third quarter of 1996 and 1995, respectively.
16
<PAGE> 17
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Columbus' financial condition and operating results continue to be
superior to most of its peer energy companies. As of the end of the first nine
months of 1996, shareholders' equity was $14,690,000, despite repurchase of
86,100 shares of treasury stock, up from $13,186,000 at November 30, 1995.
Existing positive working capital of $1,221,000 combined with the Company's
anticipated future cash flow should be sufficient to fully fund all
expenditures required to develop its undeveloped reserves as well as allow
participation in a modest exploratory drilling program. The amount by which
its outstanding loan balance is exceeded by the $7,000,000 bank borrowing base
is also available if needed but has been designated by management for
acquisitions of new oil and gas properties. However, the bank loan itself is
not so restricted and may be used for any legal corporate purpose.
Both nine months and third quarter 1996 discretionary cash flow and
net earnings results showed a significant improvement over fiscal 1995's
similar periods. This was an outgrowth of higher prices (despite hedging
deductions) and improved production of both crude oil and natural gas reported
for both 1996 periods and will be discussed later in greater detail. It is
particularly noteworthy that discretionary cash flow for 1996's first nine
months was up 49% while net earnings more than tripled.
To date fiscal 1996's development program has been much more rewarding
than that of 1995. In December, an acquisition was completed of additional
working interests in producing natural gas wells in several fields near Laredo
in Webb and Zapata Counties, Texas at a $2.63 million cost utilizing bank
borrowings and was effective as of November 1, 1995. A second acquisition in
the Laredo area of $500,000 was closed effective June 1, 1996. Subsequent
drilling successes and higher prices have combined to make these added working
interests an excellent contributor to 1996's results to date.
For the third quarter of 1996, revenues increased by 41% compared to
1995 due to the aforementioned higher oil and natural gas production and prices
while net income of $456,000, or $.15 per share, for 1996 is a significant
improvement over last year's $50,000, or $.02 per share. Proved developed and
undeveloped natural gas and crude oil reserves as of August 31, 1996 benefitted
from higher prices which restored some reserves and reduced this year's third
quarter depletion expense both on a BOE unit basis as well as on a percentage
of sales.
17
<PAGE> 18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - (Continued)
Management has steadfastly subscribed to its position that the best
measure of a company's cash flow is one determined before any consideration is
given to working capital changes or deduction of exploration expenses. This is
otherwise known as discretionary cash flow ("DCF"). Columbus' DCF for the
first nine months of 1996 was $4,791,000 compared to $3,205,000 in 1995 which
also included $362,000 attributable to its former Canadian subsidiary. For the
third quarter periods only where there was no such inclusion from that source,
the results were an even more impressive $1,538,000 versus $802,000.
Management continues its objection to the Financial Accounting
Standards Board Statement No. 95 requirement that operating cash flow be
determined after consideration of working capital changes. It will continue to
reflect its opinion on this matter in all public filings and reports because
this pronouncement ignores entirely the significant impact that the timing of
income received for, or expenses incurred on behalf of, third party owners in
wells has on working capital. This is particularly true for Columbus where it
serves as an operator but holds a fairly small interest in several such
properties with a significant activity level.
Sales volume of natural gas averaged 7,412 Mcfd during third quarter
of 1996 which was up 42% from 1995's average of 5,221 Mcfd while oil sales were
614 barrels per day in 1996 compared to 627 in third quarter 1995.
Management's stated goal for 1996 had been to surpass a former record level of
2,200 barrels of oil equivalent per day by 1996's third quarter. It has not
accomplished this objective for a variety of reasons with the most significant
being a delay in developing its Williston Basin oil reserves. While August
1996's production did approximate 1,874 BOE/D, several completed gas wells were
either connected late in the month or will be during the fourth quarter. It
should be noted that production for the third quarter of both years was solely
from U.S. operations.
Columbus' hedges of natural gas and oil prices are covered in some
detail in "Results of Operations - Oil and Gas Revenues and Operating Costs" as
well as Note 5 to the financial statements in this Form 10-Q.
18
<PAGE> 19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
The Company's operation and management services segment remains
profitable despite divesting its most profitable source generated in Canada
from processing fees. Fortunately, expenses have been sufficiently reduced
that positive results are generated.
Columbus had outstanding borrowings of $3,200,000 as of August 31,
1996 against its line of credit with Norwest Bank Denver, N.A. of which
$2,700,000 had been borrowed in December 1995 and $500,000 in June, 1996 for
the aforementioned property acquisitions. The Seventh Amendment to the credit
agreement as of August 30, 1996 reduced the LIBOR interest rate to LIBOR plus 1
1/2% and extended the revolving period to July 1, 1999 and the maturity of the
term loan to July 1, 2003. This loan continues to be collateralized by its oil
and gas properties. At the end of the third quarter 1996, the ratio of bank
debt to shareholders' equity was 0.22 and to total assets was 0.15. The debt
outstanding at the end of the quarter used a LIBOR option at an average
interest rate of 7.35%. During September 1996, the outstanding debt was
additionally reduced by $500,000.
During the first nine months of 1996, capital expenditures incurred on
oil and gas properties totaled $5,849,000 (including acquisitions of
$2,981,000). These expenditures were primarily directed toward development
drilling and recompletions in the South Texas and Gulf Coast areas as well as
prospect costs in the new Louisiana AMI.
Columbus continued its share repurchase program during the first nine
months of 1996 by acquiring an additional 86,100 shares out of a 300,000-share
repurchase authorization in February, 1995. That resolution restricted
purchases to a maximum price of $8.75 from available cash and not with bank
borrowings. There are 16,000 remaining authorized but unpurchased shares.
RESULTS OF OPERATIONS
Revenues and expenses for 1996's third quarter can be realistically
compared with 1995's like period because the latter did not contain Canadian
subsidiary results following its divestiture on February 24, 1995.
19
<PAGE> 20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Oil and Gas Revenues and Operating Costs
Reporting U.S. operations only, the following table shows comparative
crude oil and natural gas revenues, sales volumes, average prices and
percentage changes between periods for the second quarters of 1996 and 1995 and
the second quarter of 1996 versus the first quarter of 1996.
<TABLE>
<CAPTION>
Third Quarter
------------------ % Second Qtr. %
1996 1995 Change 1996 Change
----- ------ ------- ----------- ------
<S> <C> <C> <C> <C> <C>
Natural gas revenues M$ $ 1,445 $ 722 100 % $ 1,424 1 %
Oil revenue M$ $ 1,068 $ 943 13 % $ 1,215 (12)%
Natural gas sales volumes:
Millions of cubic feet 682 480 42 % 662 3 %
MCF/day 7,412 5,221 7,190
Oil sales volumes:
Barrels 56,500 57,659 (2)% 61,576 (8)%
Barrels/day 614 627 669
Average price received:
Natural gas - $/MCF $ 2.12 $ 1.50 41 % $ 2.15 (1)%
Oil - $/BBL $ 18.91 $ 16.35 16 % $ 19.74 (4)%
</TABLE>
Natural gas revenues increased 100% in the third quarter of 1996 over
1995's quarter and were primarily generated by improved prices plus the
additional interests related to the property acquisitions as well as from newly
developed wells. Average prices for natural gas rose 41% in the third quarter
of 1996 compared with last year. Increased demand and severely depleted
storage levels following an extended winter heating season contributed to this
improvement. Reported 1996 quarterly revenues were reduced by $165,000 ($.24
per Mcf) from hedging of natural gas prices while 1995's quarter had no hedging
activity or otherwise the difference in revenues would have been an even more
dramatic 123%. Sales volumes for the third quarter of 1996 versus the second
quarter of 1996 were higher by 3% which generated a 1% increase in natural gas
revenues which overcame the 1% lower average prices brought about by the
hedging losses.
Oil revenues for the third quarter were up 13% over 1995's similar
quarter as a result of a 16% increase in the average price received which
overcame 2% lower sales volumes. Crude oil production improved because two
new Jackson sand oil wells in the Sralla Road field produced for a full quarter
and overcame normal decline elsewhere while the Williston Basin oil development
program was further deferred pending completion of a 3-D seismic program. Oil
revenues and average price for the third quarter of 1996 have been reduced by
$67,500, or $1.19 per barrel, due to hedging losses. No oil hedges existed in
the 1995 quarter.
20
<PAGE> 21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
When compared to the second quarter of 1996, third quarter 1996 U.S.
oil revenues were 12% lower because of a 4% decrease in the average price per
barrel, increased hedging deductions, and 8% lower sales volumes.
No comparisons of oil and gas revenues and operations in Canada are
possible because of the spin-off of Resources in February 1995. The following
amounts were included in Columbus' 1995 first quarter results.
<TABLE>
<CAPTION>
First Quarter
--------------------
1995
-------
<S> <C>
Natural gas revenues M$ $ 492
Oil and plant liquids
revenues M$ $ 141
Natural gas sales volumes:
Millions of cubic feet 453
MCF/day 5,035
Oil and plant liquids
sales volumes:
Barrels 12,107
Barrels/day 135
Average price received:
Natural gas - $/MCF $ 1.09
Oil and liquids - $/BBL $ 11.61
</TABLE>
Lease operating expenses in the U.S. for the 1996 quarter were lower
than last year's quarter on a barrel of oil equivalent basis at $2.94 compared
to $3.30 in 1995 even though total costs were higher because of additional
wells, several expensive workovers plus the 1996 property acquisitions.
Operating costs in the U.S. as a percentage of revenues have decreased in 1996
to 20% compared to 28% in 1995's third quarter as the latter suffered from
lower product prices.
Production and property taxes approximated 9 to 10% of revenues in both
nine month periods. The relationship of taxes and revenue is not always
directly proportional because some local jurisdiction's taxes are based upon
reserve evaluations as opposed to actual revenues or production for a given
period.
Drilling for the 1996 third quarter was very active with seven (0.83
net) successful development well gas completions, one (0.34) successful
exploratory oil well and two (0.59 net) dry holes in the Laredo area.
Recompletion activity of behind-the-casing gas reserves in the B.R. Cox field
was finally commenced during the third quarter on two wells. A third well with
two zones available for recompletion was begun in early September and Columbus
has a
21
<PAGE> 22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
100% working interest in this well as other owners non-consented this
recompletion attempt. We remain confident that a recompletion program will
restore some of the reduced productivity in that gas field.
As previously reported in its 1995 annual report 10-K and prior 1996
Form 10-Q's, the Company has varying interests from 6.25% to 12.50% in 44,140
gross acres of leaseholds in a three-township Area of Mutual Interest ("AMI")
in St. Landry and Avoyelles Parishes in mid-Louisiana. This leasehold block
includes one lease of approximately 15,000 acres that is under an option which
must be exercised into new five year leases consisting of 2,000 acres every six
months for the next four years. As the option is exercised by the operator,
Belco Oil & Gas, the cost of same will not only be free of additional cost to
Columbus but, assuming the option is exercised in full, a profit of over
$400,000 will be realized by Columbus. The Company held 3,517 net acres at
August 31 but this could be reduced by about 500 net acres if an option granted
a co-venturer is exercised by October 28th.
These leaseholds overlay a trend of fractured Austin Chalk formation
at a depth of 15,000 feet in which there is a 250 foot section of limestone
containing oil both in the fracture system as well as in the porosity of the
matrix rock. Information related to the reservoir characteristics has been
established by numerous wells within the AMI that have penetrated this zone
while drilling to the deeper Tuscaloosa formation during the 1970's and
1980's. Also, several oil wells have been successfully completed in this zone
in both vertical and horizontal wells. The existence of economically
recoverable oil reserves under this property was a fairly well accepted fact.
However, past problems with the design of equipment available to drill and
complete the horizontal portion of the holes plus having to deal with
temperatures in excess of 300 degrees Fahrenheit and a geo-pressured reservoir
of about 10,000 psia led to excessive costs and brought the ultimate return on
investment into question. Accordingly, most of the Austin Chalk trend in
Louisiana remained fairly dormant for the five year period preceding 1996 while
in Central Texas the activity level was accelerating as a result of improved
productivity and significantly improved design of downhole horizontal drilling
equipment.
Several outstanding completions of this identical zone in the
Brookeland Field on the Texas-Louisiana border, and in the Masters Creek Field
area of Vernon and Rapides Parishes, Louisiana rejuvenated the entire geologic
trend resulting in several huge acreage block assemblages with multi-rig
development programs announced by firms which include Union Pacific Resources,
Amoco, Occidental Petroleum, Chesapeake Energy and Sonat. Leasehold prices
have escalated sharply throughout the trend area contemporaneously with several
announced single and dual lateral
22
<PAGE> 23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
well completions having initial potentials in excess of 8 million cubic feet of
gas and 4,000 barrels of oil or condensate per day. These were a direct result
of overcoming drilling problems which previously plagued most of the early
development wells in Columbus' AMI such as excessive mud losses into fractures
and equipment failures.
In the 1996 first quarter, Columbus and its three independent producer
co-venturers sold Belco 75% of their accumulated 25,000 acre leasehold and
lease option position. Belco also assumed a well bore farmout obligation which
called for a previously drilled and cased well to be re-entered and a single
lateral hole of 3,000 to 4,000 feet to be drilled at a vertical depth of about
15,000 feet. Columbus owns no interest in this re-entry well which has now
been successfully completed flowing at the rate of 2,500 BOPD and 2.7 Mmcfd.
EGY will have a 6.25% carried working interest reversion after payout of an
offset dual lateral well that should be commenced as soon as regulatory
clearances can be procured. This second well south of the re-entry will be
newly drilled from the surface and is forecasted to cost about $5 million.
Hopefully it will have a completion production rate in excess of the single
lateral re-entry well or Belco's other recently completed horizontal well
located about 13.5 miles to the southeast which tested at the rate of 4,800
BOPD and 6.0 Mmcfd from a 3,850 foot single lateral at a vertical depth of
17,000 feet.
To give our shareholders some perspective of the potential magnitude
of this new area on the Company's future reserves and cash flow, engineers had
estimated, based on pressure and performance data available from existing wells
prior to this new re-entry completion, that a successful single lateral with
similar productive capability to that established by that Martin A-1 well
should have recoverable reserves in the range of 1.2 to 1.5 million barrels of
oil with about 2 billion cubic feet of associated gas. Incidentally, this gas
has an unusually high heating value which can yield as much as a 70% bonus in
the price received, so it adds materially to an oil well's revenue stream.
Similarly, a dual lateral completion could generate reserves of upwards of
three million barrels of oil and four billion cubic feet of gas which would
yield undiscounted future net revenues to the working interest owners of as
much as $50 million from a well costing about $5 million, or less. Equally
important is an expected payout period of only four to eight months with a
large percentage of the reserves of each well being recovered during its first
three years of life. This translates into a potential cash flow stream for
EGY's 6.25% working interest participation of over $100,000 per month initially
from each dual lateral completion. Admittedly the productivity of these wells
is expected to decline fairly rapidly, but with such a fast payout, this fact
does not generate much concern.
23
<PAGE> 24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Operating and Management Services
This segment of the Company's U.S. business includes operations and
services conducted on behalf of third parties and also includes compressor
rentals. Operating and management services profit for U.S. only operations was
aided in 1996 by reduced costs as a result of the staff reductions made at the
beginning of fourth quarter 1995. There was a $172,000 profit for the U.S.
segment during first nine months of 1996 compared to an $121,000 profit for the
equivalent period in 1995.
Interest Income
Interest income is primarily earned from short-term investments whose
rates fluctuate with changes in the commercial paper rates and the prime rate.
Interest income decreased in 1996 to $36,000 from $42,000 in 1995's third
quarter primarily as result of a decreased amount of investments and lower
short-term interest rates.
General and Administrative Expenses
General and administrative expenses are considered to be those which
relate to the direct costs of the Company which do not originate from operation
of properties or providing of services. Corporate expense represents a major
part of this category although other nonbillable expenses are included. The
Company's general and administrative expenses in the third quarter of 1996 were
6% higher than last year because of increased level of professional services
and higher medical claims under the Company's self-insured plan.
Reimbursement for services provided by Columbus officers and employees
for managing Resources had been expected to decrease later in fiscal 1996 after
a Canadian-based management took over following a business combination with
another junior oil and gas company. However, merger discussions have been
placed on hold due to an apparent important oil discovery by Resources that
requires substantial evaluation. Columbus' general and administrative expense
will increase when it does occur since no further staff reductions are planned.
Reimbursement of $82,000 was realized in third quarter 1996 and $281,000 for
all of fiscal year 1995 for providing these services to Resources.
Litigation Expense
The legal costs of the Porter Farrell II lawsuit were included in this
expense item in 1995 but his appeal was dismissed in January 1996.
24
<PAGE> 25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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. Total charges for depletion expense for oil and gas properties
increased in 1996 over 1995 due to increased production and also overcame the
benefits realized from the 1995 write-down of the carrying value of certain
properties upon adoption of SFAS 121. However, the 1996 third quarter
depletion rate was $4.18 per barrel of oil equivalent compared to $4.53 per
barrel of oil equivalent in the like period of fiscal 1995 and $4.21 per barrel
of oil equivalent for all of 1995. These amounts are generally below the
industry average primarily because of Columbus' historically low finding costs.
Depreciation and amortization of office equipment and computer software is also
included in the total charge.
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 future cash flows from other
producing properties in the field.
Exploration Expense
In general, the exploration expense category relates to Company-wide
efforts to acquire and explore new prospective areas, and primarily includes
geological consulting, seismic expense and exploratory dry holes. The
successful efforts method of accounting for oil and gas properties requires
that the cost of drilling unsuccessful exploratory wells be currently expensed.
During second quarter 1996 an exploratory well drilled in Oklahoma proved non-
economic and $77,000 was expensed. During first quarter of 1995 no exploratory
dry holes were drilled but seismic survey costs of $46,000 were incurred in
Canada before Resources was divested. Accordingly, exploration expenses for
comparative nine month periods amounted to $182,000 for 1996 and $139,000 for
1995 which reduced cash flow from operations as well as net earnings, even
though considered discretionary expenses. These charges are added back to
compute discretionary cash flow. In addition, during third quarter 1996 3-D
seismic of $212,000 was incurred in Montana to locate a development well and
has been capitalized as part of the leasehold cost.
25
<PAGE> 26
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Interest Expense
Interest expense varies in a direct relationship to the amount of bank
debt and the level of bank interest rates. The average amount of bank debt
outstanding was lower for the 1995 second quarter than in 1996 but the average
interest rate paid during this latest quarter was 7.3% versus 7.8% in 1995.
Income Taxes
During the third quarter of 1996 the U.S. net deferred tax asset was
reduced to a net liability of $165,000 which is comprised of $96,000 current
deferred tax asset and $261,000 long-term tax liability. The estimated
utilization of deferred tax assets was $262,000 during the quarter. The
valuation allowance remained unchanged thus far in 1996. The effective tax
rate for 1996 was 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 in or
implied by the statements.
26
<PAGE> 27
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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10(a) - Seventh Amendment to the Amended and Restated Credit
Agreement dated as of August 30, 1996 between Columbus
Energy Corp. and Norwest Bank Colorado, N.A., Denver
dated July 1, 1992.
11 - Computation of per share earnings
27 - Financial data schedule
(b) Reports on 8-K
None
27
<PAGE> 28
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: October 11, 1996 /s/ Harry A. Trueblood, Jr.
---------------------- ---------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 11, 1996 /s/ Ronald H. Beck
---------------------- ---------------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
28
<PAGE> 29
EXHIBIT INDEX
Exhibit
No. Exhibit Description
- ------- -------------------
10(a) - Seventh Amendment to the Amended and
Restated Credit Agreement dated as of
August 30, 1996 between Columbus Energy
Corp. and Norwest Bank Colorado, N.A.,
Denver dated July 1, 1992.
11 - Computation of per share earnings
27 - Financial data schedule
<PAGE> 1
EXHIBIT 10(a)
[NORWEST BANKS LETTERHEAD]
August 30, 1996
Mr. Michael M. Logan, Vice President
Corporate Development/Natural Gas Marketing
Columbus Energy Corp.
Suite 2400 Lincoln Center Building
Denver, CO 80246
RE: Seventh Amendment to the Amended and Restated Credit Agreement
Between Columbus Energy Corp. and Norwest Bank Colorado N.A., Denver
dated July 1, 1992 ("Agreement")
Dear Mike:
I am pleased to advise that Norwest Bank has approved the proposed amendments
to the credit agreement requested in your letter of August 23, 1996. We are
contacting David Stolfa and requesting him to proceed with the Seventh
Amendment to the Amended and Restated Agreement, To wit:
(1) Revolving Period, Section 1.1, Page 8 - the termination of the Revolving
Period will be extended from 7/1/97 to 7/1/99.
(2) Maturity Date, Section 1.1, Page 7 - The maturity of the term loan will
now be 7/1/2003.
(3) LIBOR Interest Rate, Paragraph 4, Page 1 of the Note will be changed to
reflect LIBOR plus 150 basis points.
(4) The Agreement will be changed to reflect only one formal Borrowing Base
review date annually. The date will be April 1st and the calculation will
be based on an outside engineering report effective November 1st of the
prior year. Borrower or Bank shall have the right to request on
additional redetermination annually. The Bank has already begun its
semiannually determination for October 1st of this year and wishes to
complete that under the provisions of the existing agreement. Borrower
will continue to supply the Bank with all of the reporting information
required in the existing agreement and Bank will perform and informal
review semiannually.
Sincerely,
/s/ J. T. REAGAN
J. T. Reagan
Vice President
Energy and Minerals
<PAGE> 1
EXHIBIT 11
COLUMBUS ENERGY CORP.
Statement of Computation of Per Share Earnings
(Unaudited)
(In Thousands Except Per Share Data)
<TABLE>
<CAPTION>
Nine Months Three Months
Ended August 31, Ended August 31,
---------------- ----------------
1996 1995 1996 1995
---- ---- ---- ----
<S> <C> <C> <C> <C>
Primary:
Based on weighted average
shares outstanding including
the effect of common stock
equivalents:
Weighted average shares
outstanding: 3,049 3,160 3,049 3,117
Incremental shares attributable
to dilutive stock options and
warrants outstanding based on
average market price during
the period calculated using
the treasury stock method 34 18 82 22
------ ------ ------ ------
Total average common and
common equivalent shares 3,083 3,178 3,131 3,139
====== ====== ====== ======
Net earnings $1,539 $ 501 $ 456 $ 50
====== ====== ====== ======
Earnings per share $ .50 $ .16 $ .15 $ .02
====== ====== ====== ======
</TABLE>
Note: Fully diluted incremental shares for the nine months were 51,000 and
18,000 with total average common and common share equivalent shares
3,100,000 and 3,178,000 in 1996 and 1995, respectively.
Fully diluted incremental shares for the three months were 126,000 and
22,000 with total average common and common share equivalent shares
3,175,000 and 3,139,000 in 1996 and 1995, respectively.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AS OF AUGUST 31, 1996 AND THE CONSOLIDATED STATEMENTS
OF INCOME FOR THE NINE MONTHS ENDED AUGUST 31, 1996.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> NOV-30-1995
<PERIOD-START> DEC-01-1995
<PERIOD-END> AUG-31-1996
<CASH> 1,122
<SECURITIES> 0
<RECEIVABLES> 2,737
<ALLOWANCES> 116
<INVENTORY> 96
<CURRENT-ASSETS> 4,050
<PP&E> 29,775
<DEPRECIATION> 12,845
<TOTAL-ASSETS> 20,980
<CURRENT-LIABILITIES> 2,829
<BONDS> 0
0
0
<COMMON> 692
<OTHER-SE> 14,268
<TOTAL-LIABILITY-AND-EQUITY> 20,980
<SALES> 7,745
<TOTAL-REVENUES> 8,836
<CGS> 2,234
<TOTAL-COSTS> 6,130
<OTHER-EXPENSES> 17
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 207
<INCOME-PRETAX> 2,482
<INCOME-TAX> 943
<INCOME-CONTINUING> 1,539
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,539
<EPS-PRIMARY> .50
<EPS-DILUTED> .50
</TABLE>
