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, 1998
-------------------------------------------------
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 9, 1998
---------------------------- ------------------------------
Common stock, $.20 par value 4,081,852
<PAGE>
COLUMBUS ENERGY CORP.
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
August 31, 1998 and
November 30, 1997 3
Consolidated Statements of Operations -
Three Months and Nine Months
Ended August 31, 1998 and 1997 5
Consolidated Statement of
Stockholders' Equity -
Nine Months Ended August 31, 1998 6
Consolidated Statements of Cash Flows -
Nine Months Ended August 31, 1998
and 1997 7
Notes to the Financial Statements 9
Item 2. Management's Discussion and Analysis
of Financial Condition and
Results of Operations 18
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 29
Items 2-5. Not Applicable
Item 6. Exhibits and Reports
on Form 8-K 29
Signatures 30
2
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, November 30,
1998 1997
--------- -----------
(unaudited)
(in thousands)
Current assets:
Cash and cash equivalents $ 1,391 $ 1,857
Accounts receivable:
Joint interest partners 1,204 1,932
Oil and gas sales 1,389 2,054
Allowance for doubtful accounts (116) (116)
Inventory of oil field equipment,
at lower of average cost or market 106 102
Other 73 82
-------- --------
Total current assets 4,047 5,911
-------- --------
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 35,756 33,803
Other property and equipment 1,879 2,053
-------- --------
37,635 35,856
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (18,191) (15,632)
-------- --------
Net property and equipment 19,444 20,224
-------- --------
$ 23,491 $ 26,135
======== ========
(continued)
3
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
August 31, November 30,
1998 1997
--------- -----------
(unaudited)
(in thousands)
Current liabilities:
Accounts payable $ 2,405 $ 3,023
Undistributed oil and gas
production receipts 324 393
Accrued production and property taxes 469 551
Prepayments from joint interest owners 380 565
Accrued expenses 383 377
Income taxes payable (Note 3) 59 42
Deferred income taxes (Note 3) 217 201
Other 15 37
--------- ---------
Total current liabilities 4,252 5,189
--------- ---------
Long-term bank debt (Note 2) 3,300 2,200
Deferred income taxes (Note 3) 68 788
Commitments and contingent liabilities
(Notes 4 and 5)
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
4,611,001 in 1998, and 4,492,068 in 1997
(outstanding 4,157,552 in 1998 and
3,883,557 in 1997) 922 898
Additional paid-in capital 19,272 18,124
Retained earnings (accumulated deficit) (1,167) 2,887
--------- ---------
19,027 21,909
Less: Treasury stock at cost
453,449 shares in 1998 and
608,511 shares in 1997 (3,156) (3,951)
--------- ---------
Total stockholders' equity 15,871 17,958
--------- ---------
$ 23,491 $ 26,135
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended Three Months Ended
August 31, August 31,
-------------------------- ----------------------------
1998 1997 1998 1997
-------- -------- -------- -------
(in thousands, except per share data)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 8,113 $ 9,919 $ 2,495 $ 3,275
Operating and management
services 988 880 362 303
Interest and other income 109 123 32 51
------- -------- -------- -------
Total revenues 9,210 10,922 2,889 3,629
------- -------- -------- -------
Costs and expenses:
Lease operating expenses 1,662 1,402 445 451
Property and production taxes 802 921 261 296
Operating and management
services 807 576 311 188
General and administrative 1,155 1,140 257 273
Depreciation, depletion and
amortization 2,834 2,382 944 892
Impairments 2,816 494 - 494
Exploration expense 477 505 49 125
Litigation expense (Note 4) - 11 - -
-------- -------- -------- -------
Total costs and expenses 10,553 7,431 2,267 2,719
-------- -------- -------- -------
Operating income (loss) (1,343) 3,491 622 910
-------- -------- -------- -------
Other expenses (income):
Interest 179 111 65 46
Other 30 (5) (4) 1
------- ------- -------- -------
209 106 61 47
------- ------- -------- -------
Earnings (loss) before
income taxes (1,552) 3,385 561 863
Provision (benefit) for income
taxes (Note 3) (590) 1,286 213 328
------- ------- ------- -------
Net earnings (loss) $ (962) $ 2,099 $ 348 $ 535
======= ======= ======= =======
Earnings (loss) per share (Note 7):
Basic $ (.23) $ .49 $ .08 $ .13
======= ======= ======= =======
Diluted $ (.23) $ .48 $ .08 $ .12
======= ======= ======= =======
Average number of common shares and common
equivalent shares outstanding:
Basic 4,232 4,310 4,209 4,279
======= ======= ======= =======
Diluted 4,232 4,392 4,266 4,372
======= ======= ======= =======
</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 Nine Months Ended August 31, 1998
(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> <C>
Balances,
December 1, 1997 4,492,068 $ 898 $18,124 $ 2,887 608,511 $(3,951)
Exercise of employee
stock options 109,910 22 592 - 27,193 (229)
Purchase of shares - - - - 241,766 (1,831)
Shares issued for Stock
Purchase Plan 9,023 2 70 - (2,275) 15
10% stock dividend - - 492 (3,092) (386,494) 2,598
Shares issued for
Incentive Bonus Plan
and directors' fees - - (57) - (35,252) 242
Tax benefit of disqualifying
disposition of incentive
stock options - - 51 - - -
Net loss - - - (962) - -
--------- ------- ------- ------- ------- -------
Balances,
August 31, 1998 4,611,001 $ 922 $19,272 $(1,167) 453,449 $(3,156)
========= ======= ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
6
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended August 31,
----------------------------
1998 1997
----------- -----------
(in thousands)
Net earnings (loss) $ (962) $ 2,099
Adjustments to reconcile net earnings
(loss) to net cash provided by
operating activities:
Depreciation, depletion, and
amortization 2,834 2,382
Impairments 2,816 494
Deferred income tax provision (benefit) (653) 1,151
Other 249 83
Net change in operating assets and
liabilities 1,776 376
-------- -------
Net cash provided by
operating activities 6,060 6,585
-------- -------
Cash flows from investing activities:
Additions to oil and gas properties (6,149) (6,802)
Additions to other assets (101) (109)
-------- -------
Net cash used in
investing activities (6,250) (6,911)
-------- -------
Cash flows from financing activities:
Proceeds from long-term debt 1,800 2,200
Reduction in long-term debt (700) (1,200)
Proceeds from issuance of
common stock 457 230
Purchase of treasury stock (1,831) (1,068)
Other (2) -
-------- -------
Net cash provided by (used in)
financing activities (276) 162
-------- -------
Net increase (decrease) in cash and
cash equivalents (466) (164)
Cash and cash equivalents at
beginning of period 1,857 1,396
-------- -------
Cash and cash equivalents at
end of period $ 1,391 $ 1,232
======== =======
(continued)
7
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (continued)
(Unaudited)
Nine Months Ended August 31,
----------------------------
1998 1997
---------- ----------
(in thousands)
Supplemental disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 177 $ 119
======= ========
Income taxes, net of refunds $ 46 $ 26
======= ========
Supplemental disclosure of non-cash
investing and financing activities None None
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
management's 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 August 31, 1998 and November 30, 1997, and the results of its
operations and cash flows for the periods presented. 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.
When 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.
The Company adopted Statement of Financial Accounting Standards ("SFAS")
No. 128, "Earnings per Share," effective for the 1998 fiscal year. Prior period
earnings per share data presented has been restated to conform with the
provisions of SFAS No. 128. The purpose of SFAS No. 128 is to simplify the
computation of earnings per share. The new standard replaces the calculation of
"primary earnings per share" with a calculation called "basic earnings per
share" and redefines "diluted earnings per share".
Earnings per share 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 diluted shares. Historical average number of shares
outstanding and earnings per share have been adjusted for the five-for-four
stock split distributed June 16, 1997 to shareholders of record as of May 27,
1997 and the 10% stock dividend distributed March 9, 1998 to shareholders of
record as of February 23, 1998.
9
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
Financial Instruments and Concentrations of Credit Risk
-------------------------------------------------------
The Company maintains demand deposit accounts with separate banks in
Denver, Colorado. The Company also invests cash in the highest rated commercial
paper of large U.S. companies, with maturities not over 30 days, which have
minimal risk of loss. At August 31, 1998 and November 30, 1997 the Company had
investments in commercial paper of $1,600,000 and $900,000, respectively. The
carrying amount of long-term debt approximates fair value because the interest
rate on this instrument changes with market interest rates.
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of cash and cash equivalents
and accounts receivable. Columbus as operator of jointly owned oil and gas
properties, sells oil and gas production to relatively large U.S. oil and gas
purchasers and pays vendors for oil and gas services. The risk of non-payment by
the purchasers, counter parties to the crude oil and natural gas swap agreements
or joint owners is considered minimal. The Company does not obtain collateral
from its oil and gas purchasers for sales to them. Joint interest receivables
are subject to collection under the terms of operating agreements which provide
lien rights to the operator.
Oil and Gas Properties
----------------------
The Company follows the successful efforts method of 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 on
exploratory operations are expensed. Dry hole costs associated with developing
proved fields are capitalized. Expenditures for additions, betterments and
renewals are capitalized. Exploratory geological and geophysical costs are
expensed when incurred.
Upon sale or retirement of proved properties, the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and any gain
or loss is credited or charged to income if significant. Abandonment,
restoration, 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.
10
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
Provision for depreciation and depletion of capitalized exploration and
development costs are computed on the unit-of-production method based on proved
reserves of oil and gas, as estimated by petroleum engineers, on a property by
property basis. Unproved properties are assessed periodically to determine
whether they are impaired. When impairment occurs, a loss is recognized by
providing a valuation allowance. When leases for unproved properties expire, any
remaining cost is expensed.
An impairment loss on oil and gas properties is reported as a component of
income from continuing operations. The Company recognizes an impairment loss
when the carrying value exceeds the expected undiscounted future net cash flows
of each property pool at which time the property pool is written down to the
fair value. Fair value is estimated to be a discounted present value of expected
future net cash flows with appropriate risk consideration.
The Company follows the entitlements method of accounting for gas balancing
of gas production. The Company's gas imbalances are immaterial at November 30,
1997 and August 31, 1998.
Other Property and Equipment
----------------------------
Other property and equipment consists of office and computer equipment.
Gains and losses from retirement or replacement of other properties and
equipment are included in income. Betterments and renewals are capitalized.
Maintenance and repairs are charged to operating expenses. Depreciation of other
assets is provided on the straight line method over their estimated useful
lives.
Accounting for Stock-Based Compensation
---------------------------------------
The Financial Accounting Standards Board ("FASB") issued Statement No. 123,
"Accounting for Stock-Based Compensation". This statement prescribes the
accounting and reporting standards for stock-based employee compensation plans
and was effective for the Company's 1997 fiscal year. The Company uses the
alternative pro forma annual disclosures as permitted in the Standard.
New Accounting Pronouncements
-----------------------------
SFAS No. 130, "Reporting Comprehensive Income," was issued in June 1997 and
establishes standards for reporting and display of comprehensive income and its
components (revenues, expenses, gains, and losses) in a full set of
general-purpose financial statements. This statement is effective for financial
11
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
statements for periods beginning after December 15, 1997. The adoption of this
statement will not have a material impact on the Company's financial statements.
In June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information," effective for fiscal years beginning
after December 15, 1997. The Company must apply this statement no later than its
fiscal year ending November 30, 1999. SFAS No. 131 requires disclosing segment
information using the "management approach" and replaces the "industry segment"
approach using SFAS No. 14. The segment information previously presented is not
expected to materially change when SFAS No. 131 is adopted.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," effective for fiscal years beginning after
June 15, 1999. The Company must apply this statement no later than its fiscal
year ending November 30, 2000. SFAS No. 133 requires recording all derivative
instruments as assets or liabilities measured at fair value. This Statement is
not expected to materially affect the Company's financial statements.
(2) LONG-TERM DEBT
The Company has a credit agreement with Norwest Bank Denver, N.A. that was
amended on September 8, 1998 to extend the revolving period to July 1, 2000 when
it entirely converts to an amortizing term loan which matures July 1, 2003. The
credit agreement is collateralized by a first lien on oil and gas properties.
As requested by the Company, the borrowing base was limited to $10,000,000
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 amount 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.
12
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
Consolidated income taxes are payable only when taxable income exceeds available
net operating loss carryforwards and other credits.
The Tax Reform Act of 1986 limits the use of corporate tax carryforwards in
any one taxable year if a corporation experiences a 50% change of ownership.
Columbus experienced such a change of ownership in October 1987 which limits its
use of pre-change ownership net operating losses to approximately $900,000 in
each subsequent year.
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.
The provision (benefit) for income taxes consists of the following (in
thousands):
Nine Months Ended August 31,
---------------------------
1998 1997
------ ------
Current:
Federal $ 6 $ 34
State 57 101
------ ------
63 135
------ ------
Deferred:
Federal (632) 1,032
Use of loss carryforwards 5 76
State (26) 43
------ ------
(653) 1,151
------ ------
Total income tax (benefit) expense $ (590) $1,286
====== ======
13
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
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:
Percent of Pretax Earnings
Nine Months Ended August 31,
----------------------------
1998 1997
---- ----
U.S. Statutory rate (34)% 34 %
State income taxes 2 3
Other (6) 1
---- ---
(38)% 38 %
==== ====
During the nine months of fiscal 1998, 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):
Current Year
------------------------------------------
Stock-
Dec. 1, holders' August 31,
1997 Equity Operations 1998
-------- --------- ----------- -----------
Deferred tax assets:
Pre-1987 loss carryforwards $1,053 $ - $ - $1,053
Post-1987 loss carryforwards 540 - - 540
Percentage depletion
carryforwards 1,304 - - 1,304
State income tax loss
carryforwards 105 - (5) 100
Other 327 - (7) 320
------- ---- ------ ------
Total 3,329 - (12) 3,317
Valuation allowance
(long-term) (1,443) - - (1,443)
------- ---- ------ ------
Deferred tax assets 1,886 - (12) 1,874
-------- ---- ------ ------
Tax benefit of disqualifying
disposition of incentive
stock options - 51(a) (51) -
------- ---- ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (2,875) - 716 (2,159)
------- ---- ------ ------
Net tax asset (liability) $ (989) $ 51 $ 653 $ (285)
======= ==== ====== ======
(a)Credited to additional paid-in capital.
14
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
The Company has net operating loss carryforwards (in thousands) available
at November 30, 1997 as follows:
Net
Expiration Year Operating Loss
--------------- --------------
1999 $ 1,808
2000 903
2001 387
2010 1,589
-------
$ 4,687
=======
For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of approximately $6,056,000 as of November 30, 1997. The Company
also has percentage depletion carryforwards of $3,638,000 which do not expire.
State income tax operating loss carryforwards of $1,730,000 were available at
November 30, 1997.
(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) COMMITMENTS AND CONTINGENT LIABILITIES
When the Company uses natural gas and crude oil swaps they are considered
financial instruments with off-balance sheet risk which are used in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those instruments involved, to varying degrees,
elements of market and credit risk in excess of the amount recognized in the
balance sheets. The Company had no natural gas or crude oil swaps outstanding as
of August 31, 1998.
The Company is not aware of any events of noncompliance in its operations
with any environmental laws and regulations nor of any material potential
contingencies related to environmental issues. The exact nature of environmental
control problems, if any, which the Company may encounter in the future cannot
be predicted, primarily because of the changing character of environmental
requirements that may be enacted with applicable jurisdictions.
15
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
(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 $185,000 and $189,000 for the nine months of 1998 and
1997, respectively.
16
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
(7) EARNINGS PER SHARE
The following table provides a reconciliation of basic and diluted earnings
per share (EPS):
Nine Months Three Months
Ended August 31, Ended August 31,
--------------- ---------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands,
except per share data)
Reconciliation of basic and diluted
EPS share computations:
Income (loss) available to common
shareholders - basic and
diluted EPS (numerator) $ (962) $ 2,099 $ 348 $ 535
======= ======= ======= ======
Shares (denominator):
Basic EPS 4,232 4,310 4,209 4,279
Effect of dilutive option
shares - 82 57 93
------- ------- ------- ------
Diluted EPS 4,232 4,392 4,266 4,372
======= ======= ======= ======
Per share amount:
Basic EPS $ (.23) $ .49 $ .08 $ .13
======= ======= ======= ======
Diluted EPS $ (.23) $ .48 $ .08 $ .12
======= ======= ======= ======
Number of shares not
included in basic EPS that
would have been antidilutive
because exercise price of options
was greater than the average market
price of the common shares 170 67 170 67
======= ======= ======= ======
Historical average number of shares outstanding and earnings per share have
been adjusted for the five-for-four stock split distributed June 16, 1997 to
shareholders of record as of May 27, 1997 and the 10% stock dividend distributed
March 9, 1998 to shareholders of record as of February 23, 1998.
17
<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
Third quarter results continued to suffer from the lowest average crude oil
prices in the last ten years. Average natural gas prices also were lower than
1997's third quarter while natural gas production was up 2% compared to last
year's quarter. Third quarter 1998's cash flow was primarily reduced by those
weak product prices plus the shut-in of several oil wells so it fell
significantly below 1997's similar quarter. Net quarterly earnings of $348,000,
or $0.08 per share, were 35% below last year's net earnings of $535,000, or
$0.13 per share, which enjoyed natural gas and oil prices near the highest
levels of any quarter in recent years.
Shareholders' equity as of the end of the third quarter 1998 decreased to
$15,871,000 from $17,958,000 at November 30, 1997 primarily due to first quarter
impairment charges. Working capital was a temporary negative $205,000 as of
August 31, 1998 when a sizable accrual of accounts payables related to the
accelerated drilling program occurred in August but these were subsequently paid
early in September using a bank draw. Cash flow for the fourth quarter, in
conjunction with additional bank borrowings should provide a sufficient source
of funds to meet the remaining 1998 capital expenditure program. It appears the
original budget for 1998 of $6,800,000 which included developing undeveloped
reserves and funding an increased exploratory program which emphasized drilling
several natural gas reserve prospects along the Gulf Coast of Texas will now
exceed 1998's cash flow. Success to date with the Texas exploratory wildcats is
adding completion cost expenditures and will lead to the drilling of several
offset development wells so it is likely that budget will be exceeded also.
A significant portion of the costs incurred for wells drilled in late 1997
were actually paid early in 1998 and those costs appear as additions to
properties in the consolidated Statements of Cash Flows in this report. This
necessitated a short term draw from the Company's bank credit facility during
first quarter of 1998. Subsequently, there have been additional draws required
by the accelerated drilling expenditures in recent months. Regardless of the
recent need for withdrawals, management intends that the $10,000,000 credit
facility continue to be primarily targeted for acquisitions of oil and gas
properties, but obviously this credit can be used for any legal corporate
purpose and is therefore available for accelerated capital expenditures.
18
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Generally accepted accounting principles ("GAAP") require cash flows from
operating activities to be determined after giving effect to working capital
changes. Accordingly, GAAP's net cash provided from operating activities was
$6,060,000 for the nine months of 1998 which compares with $6,585,000 last year.
This GAAP cash flow coupled with use of the Company's credit facility has
provided sufficient liquidity to fund all capital expenditures to date as well
as treasury share repurchases.
However, management places greater reliance upon an important alternative
method of computing cash flow generally known as Discretionary Cash Flow ("DCF")
(which is not GAAP but is commonly used in the industry). This method calculates
cash flow before considering either working capital changes or deduction of
explora tion expenses. Since the latter expenditures can be increased or
decreased at management's discretion, DCF is often used by successful efforts
companies when making comparisons with the cash flow results of a majority of
other independent energy companies which use the full cost accounting method.
Their exploration expenses are capitalized and do not adversely affect
immediately either operating cash flow or net earnings. Columbus' DCF for the
nine months of 1998 was $4,761,000 down 29% from 1997's similar period which was
a record $6,714,000. As previously indicated, this decrease was primarily
attributable to lower crude oil and natural gas prices because daily production
stated in barrels equivalent was essentially flat compared with last year's
similar period. DCF is calculated without debt retirement requirements being
considered but in Columbus' case it does not matter since outstanding bank debt
requires no principal payments before August 1, 2000. Interest expense on the
outstanding debt has been relatively insignificant and is always deducted before
arriving at DCF anyway.
Management continues to note in all public filings and reports its strong
exception to the Statement of Financial Accounting Standards No. 95 which
directs that operating cash flow must only be determined after consideration of
working capital changes. This is based on our belief such a requirement by GAAP
ignores entirely the significant impact on working capital that the timing of
income received for, and expenses incurred on behalf of, third party owners in
several properties in which Columbus owns a small working interest but is the
operator.
However, neither DCF nor operating cash flow before working capital changes
may be substituted for net income or for cash available from operations as
defined by GAAP. Furthermore, currently reported cash flows, however defined,
are not necessarily indicative that there will be sufficient funds for all
future cash requirements. For the first nine months of 1998, GAAP cash flow was
much higher than DCF.
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
At the present time, the Company has no hedges in place of either crude oil
or natural gas prices similar to those swaps it negotiated in prior years. As a
result the Company's current oil and gas revenues are fully exposed to risk of
declining prices such as have occurred during fiscal 1998 to date. However, it
will be able to fully benefit from any price increases should these occur during
the balance of 1998 or during fiscal 1999.
Columbus had outstanding borrowings of $3,300,000 as of August 31, 1998
against its $10,000,000 line of credit with Norwest Bank Denver, N.A. which is
collateralized by oil and gas properties. At the end of the third quarter 1998,
the ratio of bank debt to shareholders' equity was 0.21 and to total assets was
0.14 and outstanding debt used a LIBOR option with an average interest rate of
7.2%. Subsequent to the end of the third quarter, Columbus has drawn down an
additional $1,400,000 to pay accelerated drilling expenses, restore its positive
working capital position and purchase treasury shares in September as discussed
below. The net increase (or decrease) of long-term debt directly affects cash
flows from financing activities as do the purchase of treasury shares and
proceeds from the exercise of stock options.
Working capital at August 31, 1998 had declined to a negative $205,000 from
a positive $722,000 at November 30, 1997 for reasons discussed above. Actual
nine month's capital expenditures for 1998 only were $4,769,000 for additions to
oil and gas properties and $1,831,000 for the purchase of 241,766 treasury
shares affected working capital. However, the foregoing property capital
expenditures differ from the amount shown in the consolidated Statement of Cash
Flows which also includes cash payments made during 1998 for 1997 expenditures
which had been incurred but not yet paid as of 1997's year end. Those extra
expenditures also contributed to the increased borrowings in 1998.
The Company has been authorized by its Board of Directors throughout the
past several years to repurchase its common shares from the market subject to
certain price limitations. During May 1998 an additional 200,000 shares were
authorized for repurchase at prices not to exceed $8.25 per share. This excluded
a small number of shares which remained to be acquired from prior
authorizations. For the first nine months of fiscal 1998, 241,766 shares were
repurchased (246,731 shares after the effect of the 10% stock dividend on
certain shares) at a restated average price of $7.36 per share.
Subsequently, during September and October 1998, an additional 75,700
shares have been acquired at an average price of $6.36 per share with
approximately 59,000 shares remaining to be purchased under the May, 1998
authorization.
20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Impact of the Year 2000 issue. The Year 2000 issue is the result of
computer programs being written using two digits rather than four, or other
methods, to define the applicable year. Computer programs that have
date-sensitive software may recognize a date using "00" as the year 1900 rather
than the year 2000 and could result in a system failure or miscalculations
causing disruptions of operations such as a temporary inability to process
transactions, transmit invoices or engage in similar normal business activities.
The Company upgraded its major system computer software in 1997 to a new
release of a major software vendor that is compliant with the year 2000.
Columbus has started its review of other less important systems as well as its
significant suppliers, purchasers, and transporters of oil and gas to determine
the extent to which the Company might still be vulnerable to other failures and
what the impact might be on its operations.
The Company's interest in wells operated by other companies is not
considered to be as important but it is attempting to determine to what extent
those companies are ready for the year 2000. Outside services are used for its
payroll and medical benefits processing and those companies have notified the
Company that updates to their software that is year 2000 compliant will be
available before year-end 1998. The Company is also somewhat dependent upon
personal computers and certain spreadsheet and word processing software programs
which may not be year 2000 ready at present. Evaluations will be made so as to
establish which of those systems are critical and need to be remedied.
The Company also relies on non-information technology systems, such as
office telephones, facsimile machines, air conditioning, heating, elevators in
its leased office building, which may have embedded technology such as micro
controllers and are generally outside of its control to assess or remedy. These
might adversely impact the Company's business but in management's opinion would
not create a material disruption.
As previously disclosed, the major system computer software upgrade
performed in 1997 cost $16,000. Management expects that this represents the
majority of the costs, including replacement of any non-compliant information
technology system, required to meet its goal of being year 2000 ready for
mission-critical systems. The Company does not believe that any loss of revenue
will occur as a result of the year 2000 problem but regardless of efforts to
identify and remedy such problems, there could be year 2000 related failures
that cause some disruption. The Company has not yet established a contingency
plan should year 2000 failures occur and does not yet know if it will in fact
create a contingency plan.
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
RESULTS OF OPERATIONS
During 1998's third quarter, lower oil and gas sales were responsible for
gross revenues decreasing by 24% while operating income declined to $622,000
compared with $910,000 in 1997 despite reduced costs. Other comparisons for the
1998 quarter versus 1997 related to prices, production and oil and gas sales are
covered later in this section.
Thus far during 1998, the Company postponed all Williston Basin oil
drilling. It has accelerated its exploration efforts by acquiring acreage and
3-D seismic data and agreeing to drill at least three new onshore Gulf Coast
wildcats located between Houston and Corpus Christi which have all been
successful. These include the Wilcox discovery discussed below as well as a Frio
gas discovery in Matagorda County and the Vicksburg gas discovery in Jim Wells
County reported in the prior quarter. These prospects were considered
particularly attractive because they offered initial well sites which could
produce from several different zones in the same well bore. Acquisition costs
inclusive of acreage and 3-D seismic approximate $700,000 net to Columbus.
For 1998's third quarter drilling results, four gross wells (1.96 net WI)
were all located in the onshore Gulf Coast area of Texas. These included one
(.65 net WI) successful development gas well and one successful (.20 net WI)
exploratory oil well both of which were extensions of the Sralla Road Field in
Harris County. Also one (.615 net WI) development dry hole was drilled in Jim
Wells County, but a very important Wilcox discovery gas well (.50 net WI) was
completed at its El Squared prospect in Bee County.
The Sralla Road Field wells included the Cedar Bayou #3 (.65 net WI) offset
extension to the northeast which began production in late August at an initial
daily rate of approximately 600 Mcf of natural gas and 35 barrels of oil and
that gas production has recently stabilized at approximately 280 Mcfd. The
successful oil discovery was the Jones #1 (.20 net WI) which extended this field
over one mile to the southwest and apparently is separated from the gas cap by a
cross fault. It flow tested 240 barrels of oil and 225 Mcf of natural gas per
day on an 8/64" choke and is a new reservoir oil discovery. It is currently
shut-in awaiting completion of a gathering line through a heavily populated area
as the gas cannot be flared. This pipeline is expected to be completed in the
fourth quarter.
As described in prior quarterly reports, the most significant exploratory
test well to be drilled in recent years was the Long #1 well in Bee County which
prospect is within an area of numerous prolific, multi-zone oil and natural gas
fields. A 50% participation was acquired in an acreage block of 4,024 acres
which has 3-D seismic coverage. The initial test well was drilled to about
22
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
10,700 feet and tested three Slick and two Luling sands of the Wilcox formation.
The Long #1 has been completed in 38 feet of perforations in the two uppermost
Slick sands which were 46 feet and 37 feet thick respectively, between the
depths of 9704 and 9835 feet. Also, a third Slick sand was penetrated which was
183 feet thick and also flowed natural gas and water from the top 40 feet.
However, this zone is proposed to be completed in a companion well which will be
drilled a few hundred feet northwest where the third Slick should be found at a
much higher structural position. This will also add the potential of
successfully completing one or both of the two 90-foot thick Luling sands that
were penetrated in the first well bore which also had gas shows but the logs
indicated they were probably wet. It is expected this second well bore will be
commenced later in October after further review of the seismic has helped to
select a surface location where the up-to-the-coast major fault can be
penetrated in the very top of the third Slick sand and where the Luling sands
should be over 100 feet higher structurally.
The Long #1 was tested on various size chokes for its official Texas RRC
test and through the largest, which was a 16/64th inch choke, the well flowed at
the rate of 2.9 million cubic feet per day (MMCFD)along with 20 barrels of
condensate and 70 barrels of water per day. It has subsequently been connected
temporarily to a nearby gathering line and began selling gas in early October.
Recent sales rate exceeded 2 MMCFD with 11 barrels of condensate and 48 barrels
of water per day with a flowing tubing pressure of 1540 psi.
The aforementioned dry hole development well was an offset to the Vicksburg
sand gas discovery reported in the second quarter. This development well site
was located using subsurface control only and was off structure. At present a
3-D seismic program in this area which encompasses this acreage is being shot by
others and Columbus will have access to it early next year. This will be used to
select what should be a more favorable structural location for at least one more
Vicksburg well plus there is a possibility of deeper prospective zones to test
also.
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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
third quarters of 1998 and 1997 and the third quarter of 1998 versus the second
quarter of 1998.
<TABLE>
<CAPTION>
Third Quarter
--------------------- % Second Qtr. %
1998 1997 Change 1998 Change
------ ------ ------ ----------- ------
<S> <C> <C> <C> <C> <C>
Natural gas revenues M$ $1,914 $2,016 (5)% $ 2,017 (5)%
Oil revenue M$ $ 581 $1,259 (54)% $ 764 (24)%
Natural gas sales volumes:
Millions of cubic feet 892 874 2 % 856 4 %
MCF/day 9,696 9,497 9,303
Oil sales volumes:
Barrels 50,944 67,944 (25)% 57,570 (12)%
Barrels/day 554 739 626
Average price received:
Natural gas - $/MCF $ 2.15 $ 2.31 (7)% $ 2.36 (9)%
Oil - $/BBL $11.41 $18.53 (38)% $13.27 (14)%
</TABLE>
Natural gas revenues decreased 5% in the third quarter of 1998 when
compared to 1997's quarter solely a result of decreased prices since volumes
improved by 2%. Several gas wells were completed and connected during the
intervening months but this was offset by the sale of a Berry R. Cox Field
property and normal decline. Average gas prices were down 7% commensurate with a
lack of increased demand due to a warm winter and high percentage of storage
refill. The latest quarter compared to the second quarter of 1998 showed 4%
higher sales volumes due to production from new wells connected just prior to
the close of the quarter. However, the 9% decrease in average prices for the
quarter versus the second quarter was affected by the same storage refill
influence. Therefore, gas revenues decreased 5% as a direct result of those
lower prices since production was up 4%.
Oil revenues for 1998's third quarter were down significantly by 54% when
compared to the similar 1997 quarter which was the result of a substantial 38%
decrease in the average price and a lower sales volume of 25%. The latter
directly reflected the sharp decline of a 90%-owned Montana well which had been
recompleted uphole during 1997's third quarter and contributed its initial flush
production for the period. Also, during 1998's third quarter, several wells
became marginal and were shut down. Any well which had pump or tubing problems
was not repaired nor were workovers performed. Oil revenues for last year's
third quarter had also benefitted by $46,900 ($.69 per barrel) from crude oil
swap participation but unfortunately no such crude oil swaps were in place this
year to offer protection from this latest price debacle.
24
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
When compared with 1998's second quarter results, third quarter oil
revenues were down 24% due to a 14% decrease in the average price while
production declined 12% due to the aforementioned lack of workovers, postponed
downhole equipment repairs or replacements, and the election to shut down wells
which became uneconomic at prevailing prices.
Columbus' 1998 third quarter average sales volumes of natural gas of 9,696
Mcfd (which was a quarterly record) and oil and liquids production of 563
barrels per day equates to an average daily production of 2,179 barrels of oil
equivalent (BOE) compared to 2,330 BOE of production during 1997's third
quarter. A sale of a gas property in the Berry R. Cox field, the sharp decline
during the intervening period in the Montana oil well recompletion, as well as
the aforementioned shut-ins of several oil wells more than offset the increases
generated by new gas wells which were connected between those comparative
periods.
Lease operating expenses for the third quarter were comparable to 1997's.
Essentially all expensive workovers and downhole and surface equipment
replacements on older wells had occurred during the first six months of fiscal
1998. Lease operating costs on a BOE basis were $2.22 in 1998 compared to $2.10
in 1997 which had higher production. Operating costs as a percentage of revenues
were up to 18% as a result of lower sales versus only 14% in 1997's third
quarter when excellent prices also helped to generate record revenues for that
period.
Production and property taxes approximated 10% of revenues in 1998 and 9%
in 1997. These vary based on Texas' percentage share of the total production
where oil tax rates are lower than gas tax rates. The relationship of taxes and
revenue is not always directly proportional since several of the local
jurisdiction's property taxes are based upon reserve evaluations as opposed to
revenues received or production rates for a given tax period.
Operating and Management Services
---------------------------------
This segment of the Company's business is comprised of opera tions and
services conducted on behalf of third parties including compressor rentals and
salt water disposal facilities.
Operating and management services gross profit was $181,000 during nine
months 1998 compared to a $304,000 profit during the equivalent period in 1997.
There was only a $51,000 profit for the third quarter 1998 due to unusually high
workover expenses required to clean out sand from the well bore of a salt water
disposal well in Texas. Revenues did improve during 1998's third quarter as the
number of operated wells and drilling activity increased along with an increase
from 50% to 100% ownership interest in four compressors operating in South
Texas.
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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 during the third quarter was $32,000 in both 1998 and 1997.
General and Administrative Expenses
-----------------------------------
General and administrative expenses are considered to be those which relate
to the direct costs of the Company which do not originate from operation of
properties or providing of services. Corporate expense represents a major part
of this category.
The Company's general and administrative expenses for the third quarter of
1998 were 6% less than last year despite salary increases which were granted
effective December 1, 1997 for non-officer employees and May 1, 1998 for
officers. Costs in 1998 decreased for data processing and outside accounting
services while more labor costs were allocated by employees to operating
services portion of the Company's business for the latest period.
Reimbursement for services provided by Columbus officers and employees for
managing Resources is expected to decrease during 1998's fourth quarter. This is
based on the assumption that the new President and Chief Executive Officer who
has purchased a 4.5% equity position in Resources as of June 30, 1998 will be
adding staff during the next several months. Notice of termination of the
services contract by Resources requires only 30 days but requires a 90 day
notice for Columbus to completely withdraw from providing personnel services.
When such notice does occur, it is expected that Columbus' general and
administrative expense will rise commensurately since staff reductions are not
presently contemplated although some contract services could be reduced.
Reimbursement of $62,000 for 1998 compares with $58,000 during the third quarter
of 1997 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 for the period compared to proved
reserves of each successful efforts property pool. This expense is not only
directly related to the level of production, but also is dependent upon past
costs to find, develop, and recover related reserves in each of the cost pools
or fields. Depreciation and amortization of office equipment and computer
software is also included in the total charge.
26
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Total charges for this expense item increased over 1997 as a result of
increased production and development expenditures in the intervening period as
well as reduced reserves in several cost pools brought about by lower crude oil
prices. This resulted in a 1998 third quarter depletion rate of $4.60 per BOE
compared with the $4.01 per BOE for the like period of fiscal 1997 and $3.91 per
BOE for all of 1997.
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 ultimately proved to be successful. Exploration charges
of $49,000 for 1998's third quarter were down from 1997's $125,000 which had
included $74,000 for a non-commercial exploratory oil well. Several exploratory
natural gas prospects will be drilled over the next few months along the Texas
Gulf Coast on leaseholds either already owned or under consideration. At present
no exploratory oil wells are planned for any of the 3-D seismic structures
mapped on our Williston Basin leasehold blocks in Montana until crude oil prices
improve. Earlier in 1998 3-D seismic costs of $135,000 had been incurred in this
area because of an anticipated improvement in crude oil prices and leasehold
expirations which will occur during 1999. All such exploration charges not only
decrease net earnings but also reduce reported GAAP cash flow from operations
even though they are discretionary expenses; however, such charges are added
back for purposes of determining DCF which is why it more nearly tracks cash
flow reported by full cost accounting companies who capitalize these costs.
Approximately $300,000 of 3-D seismic costs were originally budgeted for 1998 in
Richland County, Montana but with crude oil prices in disarray, this program was
deferred indefinitely and the money spent on Gulf Coast gas exploration.
Impairments
-----------
No impairment loss was necessary for the 1998 third quarter even though
crude oil and natural gas prices declined further from the end of the second
quarter.
27
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
The non-cash impairment loss of $2,816,000 thus far in 1998 was primarily
recognized during the first quarter with the extremely low crude oil prices
being a major contributor along with a Louisiana well's performance. These
resulted in a reduction in reserve quantities as well as the remaining carrying
value of several successful efforts pools after remaining unamortized costs
suddenly exceeded the newly calculated undiscounted future net cash flows.
Certain property pools were written down to a fair value based on an assumption
that the average future crude oil price would be $18.75 per barrel over the
remaining life of those pools. Some portion of those crude oil reserves is
expected to be restored at such time as crude oil prices improve but none of the
impairment charges may be reversed. An additional $400,000 of impairments were
also provided for probable loss in value of undeveloped acreage holdings
(unproved properties) located primarily in Louisiana plus $56,000 was expensed
for an expired lease.
Interest Expense
----------------
Interest expense varies in direct proportion to the amount of bank debt and
the level of bank interest rates. The average amount of bank debt outstanding
has been higher during 1998's third quarter than in 1997. The average bank
interest rate paid this latest quarter was 7.1% which compares to 7.2% in 1997.
Income Taxes
------------
During the first nine months of 1998, the net deferred tax liability
decreased to only $285,000 as a result of the large financial statement
impairment write-offs which substantially reduced the book versus tax temporary
differences. The liability is comprised of a $217,000 current portion and a
$68,000 long-term portion. A tax deduction of $51,000 from the benefit of
disqualifying disposition of incentive stock options has been added to
additional paid-in capital during 1998. The estimated increase in deferred tax
assets was $653,000 during the nine months. The effective tax rate for 1998 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.
28
<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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10(a)- First Amendment of Credit Agreement dated September 8,
1998 between Columbus Energy Corp. and Norwest Bank
Colorado, National Association.
10(b)- Second Amendment of Credit Agreement dated October 6,
1998 between Columbus Energy Corp. and Norwest Bank
Colorado, National Association.
27 - Financial data schedule - August 31, 1998
(b) Reports on Form 8-K
None
29
<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: October 13, 1998 /s/ Harry A. Trueblood, Jr.
--------------------------------- ----------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 13, 1998 /s/ Ronald H. Beck
--------------------------------- ----------------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
30
<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 AUGUST 31, 1998
COLUMBUS ENERGY CORP.
(Exact Name of Registrant)
1660 Lincoln Street
Denver, Colorado 80264
(Address of Principal Executive Office)
<PAGE>
Exhibit 10(a)
FIRST AMENDMENT OF CREDIT AGREEMENT
-----------------------------------
THIS FIRST AMENDMENT OF CREDIT AGREEMENT (this "Amendment"), dated as of
September 8, 1998, is by and between COLUMBUS ENERGY CORP., a Colorado
corporation (herein called "Borrower"),and NORWEST BANK COLORADO, NATIONAL
ASSOCIATION, a national banking association (herein called "Norwest").
RECITALS
A. Borrower and Norwest entered into an Amended and Restated Credit
Agreement dated as of October 23, 1996 (the "Credit Agreement"), in order to set
forth the terms upon which Norwest would make available to Borrower a line of
credit and by which the line of credit would be governed. Capitalized terms used
herein without definition shall have the same meanings as set forth in the
Credit Agreement.
B. Borrower and Norwest wish to enter into this Amendment in order to amend
further certain terms and provisions of the Credit Agreement.
AGREEMENT
NOW, THEREFORE, in consideration of $10.00 and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereby agree as follows:
1. Credit Agreement. The Credit Agreement shall be, and hereby is, amended
as follows as of the date hereof:
(a) The following shall be substituted for the definition of
"Borrowing Base Period" in Section 1.1 on page 2 of the Credit Agreement:
"Borrowing Base Period" means: (a) the period from the date of
this Agreement through March 31, 1997; (b) thereafter, until April 1,
2000, each twelve-month period beginning on April 1 of each year; and
(c) the period from April 1, 2000 to July 1, 2000.
(b) The following shall be substituted for the definition of
"Principal Payment Date" in Section 1.1 on Page 8 of the Credit Agreement:
<PAGE>
"Principal Payment Date" means: (a) the first Business Day of
each calendar month, commencing August 1, 2000, and (b) if all
Obligations due and payable on any such date are not then paid, each
succeeding day until all due and payable Obligations are paid in full.
(c) The following shall be substituted for the definition of
"Principal Payment Date" in Section 1.1 on page 8 of the Credit Agreement:
"Revolving Period" means the time period from the date of this
Agreement to July 1, 2000.
2. The Note. The Note shall be amended, such amendment to be effected by an
Allonge (the"Allonge") to be attached to the Note and to be substantially in the
form of Exhibit A attached hereto and made a part hereof.
3. Loan Documents. All references in any document to the Credit Agreement
and the Note shall refer to the Credit Agreement and the Note, as amended
pursuant to this Amendment and the Allonge.
4. Conditions Precedent. The obligations of the parties under this
Amendment and under the foregoing amendments to the Credit Agreement and the
Note are subject, at the option of Norwest, to the prior satisfaction of the
condition that Borrower shall have executed and delivered to Norwest the
following (all documents to be satisfactory in form and substance to Norwest):
(a) This Amendment.
(b) The Allonge.
(c) A Consent of Guarantor executed by CGSI in the form of Exhibit B
attached hereto and made a part hereof.
5. Representations and Warranties. Borrower hereby certifies to Norwest
that as of the date of this Amendment: (a) all of Borrower's representations and
warranties contained in the Credit Agreement are true, accurate and complete in
all material respects, and (b) no Default or Event of Default has occurred and
is continuing under the Credit Agreement.
6. Continuation of the Credit Agreement. Except as specified in this
Amendment and the Allonge, the provisions of the Credit Agreement and the Note
shall remain in full force and effect, and if there is a conflict between the
terms of this Amendment and the Allonge and those of the Credit Agreement or the
Note, the terms of this Amendment and the Allonge shall control.
-2-
<PAGE>
7. Expenses. Borrower shall pay all expenses incurred in connection with
the transactions contemplated by this Amendment, including without limitation
all fees and expenses of Norwest's attorney.
8. Miscellaneous. This Amendment shall be governed by and construed under
the laws of the State of Colorado and shall be binding upon and inure to the
benefit of the parties hereto and their successors and assigns. This Amendment
may be executed in any number of counterparts, each of which shall be an
original, but all of which together shall constitute one instrument.
Executed as of the date first above written.
COLUMBUS ENERGY CORP.
By: /s/ Michael M. Logan
------------------------
Michael M. Logan
Vice President
NORWEST BANK COLORADO, NATIONAL
ASSOCIATION
By: /s/ J. Thomas Reagan
-----------------------
J. Thomas Reagan,
Vice President
-3-
<PAGE>
Exhibit 10(b)
SECOND AMENDMENT OF CREDIT AGREEMENT
------------------------------------
THIS SECOND AMENDMENT OF CREDIT AGREEMENT (this "Amendment"), dated as of
October 6, 1998, is by and between COLUMBUS ENERGY CORP., a Colorado corporation
(herein called "Borrower"), and NORWEST BANK COLORADO, NATIONAL ASSOCIATION, a
national banking association (herein called "Norwest").
RECITALS
A. Borrower and Norwest entered into an Amended and Restated Credit
Agreement dated as of October 23, 1996, as amended by an amendment dated as of
September 8, 1998 (the "Credit Agreement"), in order to set forth the terms upon
which Norwest would make available to Borrower a line of credit and by which the
line of credit would be governed. Capitalized terms used herein without
definition shall have the same meanings as set forth in the Credit Agreement.
B. Borrower and Norwest wish to enter into this Amendment in order to amend
further certain terms and provisions of the Credit Agreement.
AGREEMENT
NOW, THEREFORE, in consideration of $10.00 and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereby agree as follows:
1. Credit Agreement. The Credit Agreement shall be, and hereby is, amended
as follows as of the date hereof:
(a) By substituting the following for Section 6.2(a) on page 33 of the
Credit Agreement:
(a) Net Worth. The Consolidated Tangible Net Worth of Borrower
shall not at any time be less than: (i) $12,000,000, plus (ii) 50
percent of: (A) Borrower's Cumulative Net Income after August 31,
1998, minus (B) an amount equal to the exploration expenses actually
incurred by Borrower after August 31, 1998 (as set forth in the line
item entitled "Exploration Expenses" in the financial statements
submitted by Borrower pursuant to Section 6.1(b) above), up to a
maximum of $5,000,000 of such exploration expenses which may be
subtracted for any Fiscal Year of Borrower.
(b) By deleting Section 6.2(c) on page 34 of the Credit Agreement.
2. Loan Documents. All references in any document to the Credit Agreement
shall refer to the Credit Agreement, as amended pursuant to this Amendment.
<PAGE>
3. Conditions Precedent. The obligations of the parties under this
Amendment and under the foregoing amendments to the Credit Agreement are
subject, at the option of Norwest, to the prior satisfaction of the condition
that Borrower shall have executed and delivered to Norwest the following (all
documents to be satisfactory in form and substance to Norwest):
(a) This Amendment.
(b) A Consent of Guarantor executed by CGSI in the form of Exhibit A
attached hereto and made a part hereof.
4. Representations and Warranties. Borrower hereby certifies to Norwest
that as of the date of this Amendment: (a) all of Borrower's representations and
warranties contained in the Credit Agreement are true, accurate and complete in
all material respects, and (b) no Default or Event of Default has occurred and
is continuing under the Credit Agreement.
5. Continuation of the Credit Agreement. Except as specified in this
Amendment, the provisions of the Credit Agreement shall remain in full force and
effect, and if there is a conflict between the terms of this Amendment and those
of the Credit Agreement, the terms of this Amendment shall control.
6. Expenses. Borrower shall pay all expenses incurred in connection with
the transactions contemplated by this Amendment, including without limitation
all fees and expenses of Norwest's attorney.
7. Miscellaneous. This Amendment shall be governed by and construed under
the laws of the State of Colorado and shall be binding upon and inure to the
benefit of the parties hereto and their successors and assigns. This Amendment
may be executed in any number of counterparts, each of which shall be an
original, but all of which together shall constitute one instrument.
EXECUTED as of the date first above written.
COLUMBUS ENERGY CORP.
By: /s/ Michael M. Logan
----------------------
Michael M. Logan
Vice President
NORWEST BANK COLORADO, NATIONAL
ASSOCIATION
By: /s/ J. Thomas Reagan
----------------------
J. Thomas Reagan,
Vice President
-2-
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<ARTICLE> 5
<LEGEND>
THE CONSOLIDATED BALANCE SHEET AS OF AUGUST 31, 1998 AND THE CONSOLIDATED
STATEMENT OF INCOME FOR THE NINE MONTHS ENDED AUGUST 31, 1998.
</LEGEND>
<CIK> 0000823975
<NAME> Columbus Energy
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<CURRENCY> U.S.DOLLARS
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> NOV-30-1998
<PERIOD-START> DEC-01-1997
<PERIOD-END> AUG-31-1998
<EXCHANGE-RATE> 1,000
<CASH> 1,391
<SECURITIES> 0
<RECEIVABLES> 2,593
<ALLOWANCES> 116
<INVENTORY> 106
<CURRENT-ASSETS> 4,047
<PP&E> 37,635
<DEPRECIATION> 18,191
<TOTAL-ASSETS> 23,491
<CURRENT-LIABILITIES> 4,252
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0
0
<COMMON> 922
<OTHER-SE> 14,949
<TOTAL-LIABILITY-AND-EQUITY> 23,491
<SALES> 8,113
<TOTAL-REVENUES> 9,210
<CGS> 2,464
<TOTAL-COSTS> 10,553
<OTHER-EXPENSES> 30
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<INTEREST-EXPENSE> 179
<INCOME-PRETAX> (1,552)
<INCOME-TAX> (590)
<INCOME-CONTINUING> (962)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (962)
<EPS-PRIMARY> (0.23)
<EPS-DILUTED> (0.23)
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