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, 1997
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 1-9872
COLUMBUS ENERGY CORP.
(Exact name of registrant as specified in its charter)
Colorado 84-0891713
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1660 Lincoln St., Denver, CO 80264
(Address of principal executive offices) (Zip Code)
(303) 861-5252
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if 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 14, 1997
Common stock, $.20 par value 3,861,752
<PAGE>
COLUMBUS ENERGY CORP.
INDEX
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
August 31, 1997 and
November 30, 1996........................................... 3
Consolidated Statements of Income -
Three Months and Nine Months
Ended August 1997 and 1996.................................... 5
Consolidated Statement of
Stockholders' Equity -
Nine Months Ended August 31, 1997............................. 6
Consolidated Statements of Cash Flows -
Nine Months Ended August 31, 1997
and 1996...................................................... 7
Notes to the Financial Statements................................ 9
Item 2. Management's Discussion and Analysis
of Financial Condition and
Results of Operations ........................................17
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.............................................27
Items 2-5. Not Applicable
Item 6. Exhibits and Reports
on Form 8-K...............................................27
Signatures................................................................28
2
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, November 30,
---------- ------------
(unaudited)
(in thousands)
Current assets:
Cash and cash equivalents $ 1,232 $ 1,396
Accounts receivable:
Joint interest partners 2,109 889
Oil and gas sales 1,598 1,544
Less allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 3) 545 631
Inventory of oil field equipment,
at lower of average cost or market 248 115
Other 42 77
-------- --------
Total current assets 5,658 4,536
-------- --------
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 34,339 28,031
Other property and equipment 2,052 2,001
-------- --------
36,391 30,032
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (15,267) (12,943)
-------- --------
Net property and equipment 21,124 17,089
-------- --------
$ 26,782 $ 21,625
======== ========
(continued)
3
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
August 31, November 30,
1997 1996
---------- ------------
(unaudited)
(in thousands)
Current liabilities:
Accounts payable $ 2,894 $ 1,292
Undistributed oil and gas
production receipts 374 54
Accrued production and property taxes 323 555
Prepayments from joint interest owners 193 258
Accrued expenses 353 348
Income taxes payable (Note 3) 143 33
Other 12 30
--------- ---------
Total current liabilities 4,292 2,570
--------- ---------
Long-term bank debt (Note 2) 3,200 2,200
Deferred income taxes (Note 3) 1,669 630
Commitments and contingent liabilities (Note 2)
Stockholders' equity:
Preferred stock authorized 5,000,000
shares, no par value, none issued - -
Common stock authorized 20,000,000
shares of $.20 par value; shares issued
4,445,558 in 1997, and 3,499,915 in 1996
(outstanding 3,874,547 in 1997 and
3,155,346 in 1996) 889 700
Additional paid-in capital 17,551 17,361
Retained earnings, since
December 1, 1987 2,819 720
--------- ---------
21,259 18,781
Less: Treasury stock at cost
571,011 shares in 1997 and
344,569 shares in 1996 (3,638) (2,556)
--------- ---------
Total stockholders' equity 17,621 16,225
--------- ---------
$ 26,782 $ 21,625
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Nine Months Ended Three Months Ended
August 31, August 31,
------------------- -------------------
1997 1996 1997 1996
------- ------- ------- -------
(in thousands, except per share data)
Revenues:
Oil and gas sales $ 9,919 $ 7,745 $ 3,275 $ 2,514
Operating and management
services 880 820 303 262
Interest and other income 123 271 51 36
------- ------- ------- -------
Total revenues 10,922 8,836 3,629 2,812
------- ------- ------- -------
Costs and expenses:
Lease operating expenses 1,402 1,477 451 502
Property and production taxes 921 757 296 253
Operating and management
services 576 648 188 231
General and administrative 1,140 783 273 242
Depreciation, depletion and
amortization 2,382 2,118 892 745
Impairments 494 165 494 -
Exploration expense 505 182 125 38
Litigation (Note 4) 11 13 - 3
------- ------- ------- -------
Total costs and expenses 7,431 6,143 2,719 2,014
------- ------- ------- -------
Operating income 3,491 2,693 910 798
------- ------- ------- -------
Other expenses (income):
Interest 111 207 46 65
Other (5) 4 1 (3)
------- ------- ------- -------
106 211 47 62
------- ------- ------- -------
Earnings before
income taxes 3,385 2,482 863 736
Provision for income taxes
(Note 3) 1,286 943 328 280
------- ------- ------- -------
Net earnings $ 2,099 $ 1,539 $ 535 $ 456
======= ======= ======= =======
Earnings per share (Note 1):
Primary $ .54 $ .40 $ .14 $ .12
======= ======= ======= =======
Fully diluted N/A N/A N/A $ .11
=======
Average number of common shares outstanding (Note 1):
Primary 3,918 3,811 3,890 3,914
======= ======= ======= =======
Full diluted N/A N/A N/A 3,969
=======
Note 1 - 1996 shares and earnings per share restated for May 27, 1997 five-
for-four stock split.
The accompanying notes are an integral part of these consolidated financial
statements.
5
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Nine Months Ended August 31, 1997
(Unaudited)
Common Stock Additional Treasury Stock
--------------------- Paid-in Retained --------------------
Shares Amount Capital Earnings Shares Amount
--------- --------- -------- -------- ------- -------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1996 3,499,915 $ 700 $17,361 $ 720 344,569 $(2,556)
Exercise of employee
stock options 52,723 11 288 - 13,333 (131)
Purchase of shares - - - - 120,514 (1,068)
Shares issued for Stock
Purchase Plan 6,996 1 62 - (1,762) 12
Shares issued for
Incentive Bonus Plan
and directors' fees - - (7) - (13,451) 105
Shares issued under
five-for-four stock
split (Note 1) 885,924 177 (179) - 107,808 -
Tax benefit of disqualifying
disposition of incentive
stock options - - 26 - - -
Net earnings - - - 2,099 - -
--------- ------- ------- ------- ------- -------
Balances,
August 31, 1997 4,445,558 $ 889 $17,551 $ 2,819 571,011 $(3,638)
=== ==== ========= ======= ======= ======= ======= =======
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
6
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
-----------------
August 31, 1997 August 31, 1996
--------------- ---------------
(in thousands)
Net earnings $ 2,099 $ 1,539
Adjustments to reconcile net earnings
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization 2,382 2,118
Impairments 494 165
Deferred income tax provision 1,151 856
Gain on asset sale - (175)
Other 83 106
Net change in operating assets and
liabilities 376 (758)
-------- --------
Net cash provided by
operating activities 6,585 3,851
-------- --------
Cash flows from investing activities:
Additions to oil and gas properties (6,802) (5,849)
Additions to other assets (109) (28)
Proceeds from sale of assets - 336
-------- --------
Net cash used in
investing activities (6,911) (5,541)
-------- --------
Cash flows from financing activities:
Proceeds from long-term debt 2,200 3,200
Reduction in long-term debt (1,200) (1,600)
Proceeds from issuance of
common stock 230 377
Purchase of treasury stock (1,068) (579)
-------- --------
Net cash provided by
financing activities 162 1,398
Net decrease in cash and
cash equivalents (164) (292)
Cash and cash equivalents at
beginning of period 1,396 1,414
-------- --------
Cash and cash equivalents at
end of period $ 1,232 $ 1,122
======== ========
(continued)
7
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
-----------------
August 31, 1997 August 31, 1996
--------------- ---------------
(in thousands)
Supplemental disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 119 $ 184
======= =======
Income taxes (refund) $ 26 $ (4)
======= =======
Supplemental disclosure of non-cash investing and financing activities:
Non-cash compensation expense
related to common stock $ - $ 20
======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
8
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
(Unaudited)
(1) BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts
of Columbus Energy Corp. ("Columbus") and its wholly-owned subsidiary, Columbus
Gas Services, Inc.("CGSI"). All significant intercompany balances have been
eliminated in consolidation. The term "Company" as used herein includes Columbus
and its subsidiary.
The consolidated financial statements of the Company have been prepared
in accordance with generally accepted accounting principles and require the use
of managements' estimates. The financial statements contain all adjustments
(consisting only of normal recurring accruals) which, in the opinion of
management, are necessary to present fairly the financial position of the
Company as of August 31, 1997 and November 30, 1996, 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.
The Company uses crude oil and natural gas swaps to manage price
exposure. Realized gains and losses on the swaps are recognized in oil and gas
sales as settlement occurs.
Earnings per share are computed using the weighted average number of
common shares outstanding. Stock options are included as common stock
equivalents, when dilutive, using the treasury stock method. Common stock
equivalents include shares issuable upon assumed exercise of dilutive stock
options using the average price for primary shares and the period end price, if
higher, for fully diluted shares. For 1997 and 1996 such common stock
equivalents were not dilutive, except for the three months ended August 31,
1996. Historical average number of shares outstanding and earnings per share
have been adjusted for the five-for-four stock split distributed June 16, 1997
to shareholders of record as of May 27, 1997.
The Company will adopt Financial Accounting Standards No. 128, "Earnings
per Share," ("SFAS No. 128") effective for the 1998 fiscal year. Earlier
application is not permitted. 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". The Company does not expect
9
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
the application of SFAS No. 128 to have a material impact on its earnings per
share calculation.
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 for
exploratory operations are expensed. Dry hole costs associated with developing
proved fields are capitalized. Expenditures for additions, betterments and
renewals are capitalized. Exploratory geological and geophysical costs are
expensed when incurred.
Upon sale or retirement of proved properties, the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and any gain
or loss is credited or charged to income if significant. Abandonment,
restoration, and dismantlement costs and salvage value are taken into account in
determining depletion rates. These costs are generally about equal to the
proceeds from equipment salvage upon abandonment of such properties. When
estimated abandonment costs exceed the salvage value, the excess cost is accrued
and expensed. Maintenance and repairs are charged to operating expenses.
Provision for depreciation and depletion of capitalized exploration and
development costs are computed on the unit-of-production method based on proved
developed reserves of oil and gas, as estimated by petroleum engineers, on a
property by property basis. Unproved properties are assessed periodically to
determine whether they are impaired. When impairment occurs, a loss is
recognized by providing a valuation allowance. When leases for unproved
properties expire, any remaining cost is expensed.
An impairment loss on oil and gas properties is reported as a component
of income from continuing operations. The Company recognizes an impairment loss
when the carrying value exceeds the expected undiscounted future net cash flows
of each property pool at which time the property pool is written down to the
fair value. Fair value is estimated to be a discounted present value of expected
future net cash flows with appropriate risk consideration.
The Company follows the entitlements method of accounting for gas
balancing of gas production. The Company's gas imbalances are immaterial at
November 30, 1996 and August 31, 1997.
10
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
Other Property and Equipment
Depreciation of other assets is provided on the straight line method over
their estimated useful lives. Gains and losses from retirement or replacement of
other properties and equipment are included in income. Betterments and renewals
are capitalized. Maintenance and repairs are charged to operating expenses.
Accounting for Stock-Based Compensation
The Financial Accounting Standards Board issued Statement No. 123,
"Accounting for Stock-Based Compensation". This statement prescribes the
accounting and reporting standards for stock-based employee compensation
plans and is effective for the Company's 1997 fiscal year. The Company has
determined it will use the alternative pro forma disclosures as permitted in
the Standard.
Comprehensive Income
The Financial Accounting Standards Board issued Statement No. 130,
"Reporting Comprehensive Income" effective for the Company's 1999 fiscal
year. The Company does not expect SFAS No. 130 to have any material effect
on its calculations of net income.
(2) LONG-TERM DEBT
The Company has a credit agreement with Norwest Bank Denver, N.A. that was
amended and restated on October 23, 1996. The credit is collateralized by a
first lien on oil and gas properties.
As requested by the Company, the borrowing base was increased to a limit of
$10,000,000 from $7,000,000 effective May 13, 1997, without regard to the
maximum allowable amount that would be set by the bank during its semi-annual
redetermination. A commitment fee of .25% is payable for any unused portion of
the credit which is the difference between the borrowing base and the
outstanding borrowings.
11
<PAGE>
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 these corporate tax carryforwards in any one taxable year is
limited if a corporation experiences a 50% change of ownership. Columbus
experienced such a change of ownership in October 1987 effectively limiting the
utilization of pre-change ownership net operating losses to approximately
$900,000 in each subsequent year. Subsequent additional ownership changes
accumulated to more than 50% by August 25, 1993 thereby causing a second
ownership change to occur. The remaining restricted post-1987 net operating loss
carryforwards were fully utilized during fiscal 1996.
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 bases of
assets and liabilities using enacted rates in effect for the year in which the
differences are expected to reverse. Deferred tax assets (net of a valuation
allowance) primarily result from net operating loss carryforwards, percentage
depletion and certain accrued but unpaid employee benefits. Deferred tax
liabilities result from the recognition of depreciation, depletion and
amortization in different periods for financial reporting and tax purposes.
Because of the Company's previous 1987 quasi-reorganization, the Company
is required to report the effect of its net deferred tax asset arising prior to
December 1, 1987 as an increase in stockholders' equity rather than as an
increase to net earnings.
12
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
The provision for income taxes consists of the following (in thousands):
Nine Months Ended August 31,
----------------------------
1997 1996
------ ------
Current:
Federal $ 34 $ 50
State 101 37
------ ------
135 87
------ ------
Deferred:
Federal 1,075 (198)
Use of loss carryforwards 76 1,054
------ ------
1,151 856
------ ------
Total income tax expense $1,286 $ 943
====== ======
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,
----------------------------
1997 1996
------ ------
U.S. Statutory rate 34% 34%
State income taxes 3 2
Other 1 2
------ ------
38% 38%
====== ======
13
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
During the nine months of fiscal 1997, certain tax assets (shown in the
table below) were utilized. The tax effect of significant temporary differences
representing deferred tax assets and liabilities and changes were estimated as
follows (in thousands):
Current Year
--------------------------------------
Stock-
Dec.1, holders' August 31,
1996 Equity Operations 1997
----- ------ ---------- -----
Deferred tax assets:
Pre-1987 loss carryforwards $1,361 $ - $ - $1,361
Post-1987 loss carryforwards 596 - (56) 540
Percentage depletion
carryforwards 1,130 - - 1,130
State income tax loss
carryforwards 88 - (20) 68
Other 308 - (5) 303
------ ------ ------ ------
Total 3,483 - (81) 3,402
Valuation allowance (1,469) - - (1,469)
------ ------ ------ ------
Deferred tax assets 2,014 - (81) 1,933
------ ------ ------ ------
Tax benefit of disqualifying
disposition of incentive
stock options - 26 (26) -
------ ------ ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (2,013) - (1,044) (3,057)
------ ------ ------ ------
Net tax asset (liability) $ 1 $ 26 $(1,151) $(1,124)
====== ====== ======= =======
The Company has net operating loss carryforwards (in thousands) available
at November 30, 1996 as follows:
Net
Expiration Year Operating loss
--------------- --------------
1999 $ 2,712
2000 903
2001 387
2003 -
2004 -
2010 1,589
-------
$ 5,591
=======
For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of approximately $6,752,000 as of November 30, 1996. The Company
also has percentage depletion carryforwards of $2,908,000 which do not expire.
State income tax operating loss carryforwards of $1,470,000 were available at
November 30, 1996.
14
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
(4) LITIGATION
Management is unaware of any asserted or unasserted claims or assessments
against the Company which would materially affect the Company's future financial
position or results of operations.
(5) CONTINGENCY
The Company entered into a natural gas swap by selling 60,000 Mmbtu per
month for the period from March 1997 through October 1997 at $2.20 per Mmbtu.
This volume represents approximately 21% of Columbus' third quarter gas
production.
Columbus also entered into a crude oil swap by selling a strip of 10,000
barrels per month for the twelve month period from November 1996 through October
1997 at an average daily price of $21.17 per barrel. This amount represents
approximately 44% of Columbus' August 1997 crude oil production. The difference
between the hedge price and the actual daily closing price on the New York
Mercantile Exchange ("NYMEX") is settled monthly.
The Company's natural gas and crude oil swaps are considered financial
instruments with off-balance sheet risk which were in the normal course of
business to reduce its exposure to fluctuations in the price of crude oil and
natural gas. Those instruments involve, to varying degrees, elements of market
and credit risk in excess of the amount recognized in the balance sheets. The
Company had natural gas and crude oil swaps outstanding subsequent to August 31,
1997 as follows:
Notional Market Value as of
Value 8/31/97
-------- ------------------
Natural gas
(9/97-10/97) $264,000 $204,660
Crude oil
(9/97-10/97) 423,400 453,700
15
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(6) RELATED PARTY TRANSACTIONS
CEC Resources Ltd. ("Resources") was a wholly-owned subsidiary of Columbus
prior to its divestiture on February 24, 1995. Reimbursement is made by
Resources to Columbus for services provided by Columbus officers and employees
for managing Resources and reduces general and administrative expense. This
reimbursement totaled $189,000 and $232,000 for the nine months of 1997 and
1996, respectively.
16
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following summarizes the Company's financial condition and results of
operations and should be read in conjunction with the consolidated financial
statements and related notes.
Liquidity and Capital Resources
Third quarter results ranked among the best quarters in history but this
was not readily evident when compared to the first quarter 1997. This was
primarily due to significant exploration and impairment charges of $619,000
($384,000 after income tax effect) which attacked net earnings. This
overshadowed the increase in natural gas production to record levels and a
modest improvement in daily crude oil production over last year. Third quarter
discretionary cash flow and sales attained a second best ever quarter ranking.
Net earnings of $535,000, or $0.14 per share, were 17% higher than last year's
net of $456,000, or $0.12 per share. It is noteworthy that nine months' cash
flow in 1997 surpassed all of fiscal 1996's cash flow while net earnings of
$2,099,000, or $0.54 per share, rose by 36% over the $1,539,000, or $0.40 per
share and equaled the entire fiscal 1996 year's net. As of the end of the third
quarter 1997, shareholders' equity had risen to $17,621,000 compared to
$16,225,000 at November 30, 1996. There was positive working capital of
$1,366,000 as of August 31, 1997 which, when combined with the Company's
forecasted future cash flow for the balance of the year, should be more than a
sufficient source of capital to finish the budgeted 1997 program to develop
undeveloped reserves plus fund the expanded exploratory program. As discussed
later, a substantial increase in the percentage working interest in the
Louisiana Austin Chalk exploratory well contributed to 1997's initial $7.1
million capital budget being raised by over $1 million. This has required a
short term draw from the Company's bank credit facility pending repayment from
the additional monthly cash flow generated from those accelerated expenditures.
The $10,000,000 credit facility has been primarily targeted by management for
acquisitions of oil and gas properties, but can be used for any legal corporate
purpose and is always available for such expanded operational expenditures.
Generally accepted accounting principles ("GAAP") require cash flows from
operating activities to be determined after giving effect to working capital
changes. Accordingly, GAAP net cash provided by operating activities of
$6,585,000 for the first nine months of 1997 compares with $3,851,000 during
1996's period. However, an important alternative measure of a company's cash
flow (not GAAP but commonly used in the industry) is one determined before
consideration of working capital changes and without deduction of exploration
expenses. This is generally known as Discretionary Cash Flow ("DCF") and is
reported by successful efforts companies for comparability purposes to the cash
flow results under the full cost accounting method used by a majority of
independent energy companies. Using the latter method, all exploration costs are
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
capitalized and therefore do not adversely affect operating cash flow or net
earnings. Since exploration expenses can be increased or decreased at
management's discretion, DCF is certainly more comparable to such full cost
accounting results. Columbus' DCF for the nine months of 1997 was a record for
such period at $6,714,000 compared to 1996's $4,791,000 which itself had been a
record and, in fact, 1997's nine months' DCF also exceeded fiscal 1996's DCF.
This 40% improvement reflects higher natural gas prices and increased crude oil
and natural gas production over last year. While DCF is calculated before debt
retirement requirements, in Columbus' case it does not matter because its
outstanding bank debt requires no principal payments before July 1999 and in
fact is what is available to either drill or retire debt at management's
discretion. Interest expense on the outstanding debt has recently been
relatively insignificant but is always deducted before computing DCF anyway.
Management notes its strong exception to Financial Accounting Standards
Board Statement No. 95 which directs that operating cash flow must only be
determined after consideration of working capital changes and continues to
reflect that position in all of its public filings and reports. Such a
requirement by GAAP ignores entirely the significant impact on working capital
that the timing of income received for, and expenses incurred on behalf of,
third party owners in wells could have on a company such as Columbus which
serves as an operator of several properties with only a small working interest
therein.
Neither discretionary cash flow nor operating cash flow before working
capital changes may be substituted for net income or cash available from
operations as defined by GAAP. Furthermore, cash flows do not necessarily
indicate they are sufficient to fund all cash requirements of a company under
any of the definitions.
Columbus' hedges (swaps) of natural gas and oil prices are discussed below
in Results of Operations as well as in Note 5 to the financial statements.
The Company's operation and management services segment remains profitable
but has not contributed meaningfully to earnings since Resources was spun-off in
February, 1995.
Columbus had outstanding borrowings of $3,200,000 as of August 31, 1997
against its line of credit with Norwest Bank Denver, N.A. which has a current
borrowing base of $10,000,000 and is collateralized by oil and gas properties.
At the end of the third quarter 1997, the ratio of bank debt to shareholders'
equity was 0.18 and to total assets was 0.12. The debt outstanding used a LIBOR
option at an interest rate of 7.1%. The net increase or decrease of long-term
18
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
debt affects reported cash flow from financing activities as does the purchase
of treasury stock and proceeds from the exercise of stock options.
Working capital at August 31, 1997 remained positive at $1,366,000
compared to $1,966,000 at November 30, 1996. This was achieved despite
expenditures of $6,802,000 for new additions to oil and gas properties out of an
expanded program for development and exploratory operations for 1997.
A 300,000-share repurchase authorized (at less than $8.75 per share) in
February 1995 was completed in March 1997 for an average repurchase price of
$7.21 ($5.77 after five-for-four stock split).
During March 1997, an additional 100,000-share repurchase was authorized
at less than $7.80 (giving effect to five-for-four stock split) per share. To
date, 85,000 shares were acquired at an average price of $7.42 per share. A
second authorization was granted in May, 1997 to become effective following
distribution of split shares in June, 1997 which permits purchase of an
additional 200,000 shares at a price not to exceed $8.25 per share. To date,
39,000 shares have been acquired at an average price of $8.06 per share.
RESULTS OF OPERATIONS
During 1997's third quarter, the Company's gross revenues increased by 29%
while operating income increased by 14% when compared to 1996 despite large
exploratory charges and an impairment provision. This was attributable to
improved crude oil production and to a record level of natural gas production
generated by the Company's successful drilling program thus far during 1997.
Other comparisons appear later for the quarter and nine months of 1997 versus
like periods in 1996 for prices, production and oil and gas sales.
With a record drilling budget approved for 1997, it should be expected
that there will be an increased number of well participations during each
period. During 1997's third quarter, ten gross wells (2.85 net) were completed
including four (.35 net) successful gas wells in the Laredo area and two (.91
net) gas cap wells in the Sralla Road oil field in Texas and a prolific Frio 16
sand natural gas discovery (.37 net) in Chambers County, Texas.
That latter well whose completion was discussed in the second quarter
report began sales in early July and has maintained a daily rate of
approximately 3,800 MMCF of gas and 70 barrels of condensate. A separate fault
block containing an additional 600 acres of prospective acreage is owned to the
south and east of the Syphrett Heirs #1 480-acre discovery fault block. This
acreage will require its own exploratory test and should be commenced later
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
in 1997. It may possibly be drilled to a depth of 11,000 feet to test the
underlying Vicksburg formation because there was a recent gas discovery
completed in this zone about two miles east of the Syphrett discovery fault
block. An uphole Frio 15 sand is also considered prospective for oil production
at a structurally higher position in the Syphrett fault block and may prove
productive in the southeast acreage block also.
Also pending completion at the end of the third quarter were two (.68 net)
small oil producers in Oklahoma along with the exploratory Austin Chalk oil well
(.55 net) in mid-Louisiana discussed below more fully.
As previously reported in Form 10-K's and various quarterly reports,
Columbus has a 12.5% working interest in a three township Area of Mutual
Interest covering 55,000 gross acres of leaseholds which overlie the fractured
Austin Chalk formation below 15,000 feet in depth in mid-Louisiana. A good
portion of this block was assembled by a co-venture group which included EGY and
75% was sold to Belco Oil & Gas. Terms included a modest profit plus a carried
25% interest in a vertical well drilled from grass roots to 15,000 feet
including updip and downdip horizontal legs approximately 3,000 to 4,000 feet in
length. This was subsequently modified to permit the use of an existing
abandoned but cased vertical hole from which to drill the two laterals at no up
front costs to Columbus or its co-venturers and a no cost vertical hole portion
later at a second location. The Morrow #23-1H's operations began in February
with Belco choosing to drill a 3,000-foot north updip lateral first. They
purposely elected to drill laterally below the base of the Austin Chalk for
reasons not clear to, and over the objections of, the co-venture group and
resulted in a dry hole. As a consequence, Belco then drilled a piggyback lateral
about 100 feet vertically higher in the prospective pay section which penetrated
numerous shows and fractures throughout this 3,100-foot horizontal hole. Belco
was disappointed with its production test from this updip lateral over a 66-hour
period which yielded a high water cut of about 70% in addition to the crude oil
and natural gas. The last few hours of test still had a fluid rate of about 66
barrels per hour of which 21% was oil (over 12 BPH) and 600,000 cubic feet of
natural gas per day.
Following the test, Belco proposed to move the drilling rig off of the well
without drilling an obligatory 4,000-foot downdip south lateral. There was
strong objections by the co-venturers which was settled by Belco relinquishing
all of its right, title and interest in the cased well bore, the updip lateral
and the 1,960-acre spacing unit to the co-venturers who took over rig
operations. Numerous problems were encountered while attempting to drill this
downdip lateral which included encountering high bottom hole pressures which
exceeded the maximum capability of weighting up the clear drilling fluid to
maintain control over the well. As a result, only 1,300 feet of the proposed
4,000-foot downdip lateral could be drilled and the well had to be killed with a
20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
conventional barite-weighted mud system which brought about a lost circulation
problem. At that point, all further efforts to finish the entire lateral were
ceased and it was generally agreed to make another attempt to drill another
4,000-foot downdip lateral from a new casing window after the 1,300-foot downdip
lateral and the updip 3,100-foot lateral had been depleted. Thereafter numerous
problems were encountered during completion operations which included packer
problems, pushing the liner out to the full 1,300 feet of lateral, inexperienced
crews, rental equipment from major service companies which did not function
properly, drilling rig equipment failures, etc. The final blow occurred when a
roughneck dropped a five inch bolt in the hole on top of the packer which
contributed to several additional days of rig and rental equipment expenses and
a "jerry-rigged" completion had to be designed which at least permitted the well
to produce.
Fortunately, Columbus only owns 55% WI of the completed well and drilling
unit so that the significant cost overruns were not entirely absorbed by it. In
any event, during a test for its initial potential, the Morrow #23-1H was
produced for a 26-hour clean-up followed by a 24-hour test period during which
the well flowed 560 barrels of 41o API gravity oil, 831 Mcf of natural gas and
1,691 barrels of a mixture of formation salt water and the clear calcium bromide
drilling fluid lost during drilling operations. The final five hours of the flow
period yielded 80 barrels of fluid per hour with an oil cut of about 25% and was
followed by a one-hour shut in pressure of 3,950 psi.
At present, the gas gathering line is being laid to the closest
transmission system which is about 7,500 feet to the south. The tank battery,
separator, treater, plus other surface equipment has been installed. Major items
remaining before the well can begin sales include a shallow water disposal well
being drilled and electricity being brought to the location. These should be
completed during October. The present plan of production is to first essentially
deplete the short downdip lateral followed by removal of the junk and bridge
plug above the updip lateral to allow it to be depleted before undertaking
mobilization of a drilling rig to attempt drilling a new 4,000-foot downdip
lateral. Whether or not other well(s) can be promoted on the acreage block
before acreage renewals are required will depend on the production performance
of the Morrow #23-1H over the next few months. Meanwhile, it has already been
determined not to exercise the remaining option acreage as the profit will not
be realized from Belco on each new lease. Should the well not perform as has
been forecasted out of two existing laterals, then it is highly unlikely the
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
development of reserves in one or more new laterals from this well bore will be
undertaken and additional exploratory or impairment charges will be incurred in
such circumstance.
Columbus' investment in this prospect through August 31, 1997 totaled
$688,000 for undeveloped leaseholds and $2,415,000 for interests in producing
wells including the Morrow #23-1H.
Oil and Gas Revenues and Operating Costs
The following table shows comparative crude oil and natural gas revenues,
sales volumes, average prices and percentage changes between periods for the
third quarters of 1997 and 1996 and the third quarter of 1997 versus the second
quarter of 1997.
<TABLE>
<CAPTION>
Third Quarter
------------- % Second Qtr. %
1997 1996 Change 1997 Change
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Natural gas revenues M$ $2,016 $1,445 40% $1,672 21%
Oil revenue M$ $1,259 $1,068 18% $1,207 4%
Natural gas sales volumes:
Millions of cubic feet 874 682 28% 809 8%
MCF/day 9,497 7,412 8,792
Oil sales volumes:
Barrels 67,944 56,500 20% 61,792 10%
Barrels/day 739 614 672
Average price received:
Natural gas - $/MCF $ 2.31 $ 2.12 9% $ 2.07 12%
Oil - $/BBL $18.53 $18.91 (2)% $19.53 (5)%
</TABLE>
Natural gas revenues increased 40% in the third quarter of 1997 when
compared to 1996's quarter as a result of higher volumes and prices. Average
prices for natural gas increased 9% in the third quarter of 1997 compared with
last year due to strong demand and a fairly tight supply of gas over storage
injection requirements. Gas revenues in the third quarter of 1997 were reduced
by $10,000 ($.01 per Mcf) and 1996's revenues were reduced by $165,000 ($.24 per
Mcf) from swaps of natural gas. Sales volumes improved by 28% over 1996's third
quarter as a result of numerous gas wells being completed and connected during
the intervening months. The latest quarter as compared with the second quarter
of 1997 showed a sales volume increase of 8% as a result of new well
connections. Also, there was a 12% increase in average prices received which
also contributed to a revenue increase of 21%.
Oil revenues for the 1997 third quarter were up meaningfully when compared
to the similar 1996 quarter because of a sales volume increase of 20% which
overcame a decrease in the average price of 2%. Crude oil production has now
reversed its continuing slide over a several year period as new wells have been
added which generated the improvement over last year's volumes. There was an
22
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
improvement of 10% over 1997's second quarter volume, also. Oil revenues for the
third quarter of 1997 were aided by $46,900 ($.69 per barrel) while third
quarter 1996 revenues were reduced by $67,500 ($1.19 per barrel) from crude oil
swaps.
When comparisons are made with the second quarter results for 1997, third
quarter oil revenues were 4% higher because of a 10% increase in production
which overcame a 5% decrease in average price per barrel received.
Columbus' 1997 third quarter average sales volumes of natural gas of 9,497
Mcfd and oil and liquids production of 747 barrels per day equates to daily
production of 2,330 barrels of oil equivalent (BOE). This is 6% above the
previous record quarter for U.S. daily production of 2,200 BOE which was
achieved during the third quarter of 1994. For the month of August, 1997 daily
production was 2,498 BOE.
Lease operating expenses for the 1997 quarter were lower than third
quarter 1996 because the prior year's quarter had several expensive workovers
performed and equipment replaced on older wells. Lease operating costs on a BOE
basis were only $2.10 in 1997 compared to $2.94 in 1996 as a result of increased
production volumes. Operating costs as a percentage of revenues was 14% in the
1997 third quarter and 20% in 1996's comparable quarter.
Production and property taxes approximated 9% of revenues in 1997 and 10%
in 1996. These vary based on Texas' percentage 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 taxes are based upon reserve evaluations as opposed to revenues
received or production rates for a given tax period.
Operating and Management Services
This segment of the Company's U.S. business is comprised of operations and
services conducted on behalf of third parties and includes compressor rentals.
Operating and management services profit has been fairly consistent
between quarters. There was a $304,000 profit during first nine months 1997
compared to a $172,000 profit for the equivalent period in 1996 as the number of
operated wells and drilling activity has increased.
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Interest Income
Interest income is earned primarily from short-term investments whose
rates fluctuate with changes in the commercial paper rates and the prime rate.
Interest income decreased slightly in 1997 to $32,000 from $36,000 in 1996's
third quarter primarily as a result of a decreased amount of investments despite
somewhat higher short-term interest rates.
General and Administrative Expenses
General and administrative expenses are considered to be those which
relate to the direct costs of the Company which do not originate from operation
of properties or providing of services. Corporate expense represents a major
part of this category although other nonbillable expenses are also included.
The Company's general and administrative expenses in the third quarter of
1997 were 13% higher than last year. Those increased costs were primarily due to
salary increases in May 1997 for officers and as of November 1996 for employees.
Reimbursement for services provided by Columbus officers and employees for
managing Resources is expected to decrease by the end of fiscal 1997 assuming
that Canadian-based management takes over following an expected business
combination that Resources is currently aggressively seeking. Columbus' general
and administrative expenses will rise commensurately since no staff reductions
are contemplated when this occurs. Reimbursement of $58,000 is down from the
$82,000 received during the third quarter of 1996 for administrative and
operational services provided to Resources.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are
calculated based upon the units of production compared to proved reserves of
each field. The expense is not only directly related to the level of production,
but also is dependent upon past costs to find, develop, and recover those
reserves in each of the pools or fields. Depreciation and amortization of office
equipment and computer software is also included in the total charge.
Total charges for depletion expense for oil and gas properties increased
over 1996 due to increased production and added development expenditures in the
intervening period. The 1997 third quarter depletion rate of $4.01 per BOE
compares with the $4.18 per BOE for the like period of fiscal 1996 and $3.86 per
BOE for all of 1996. These amounts are somewhat below the industry average
24
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
primarily because of historically lower finding costs compared to others who
have grown mostly by acquisitions.
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
for comparative third quarters amounted to $125,000 for 1997 up dramatically
from $38,000 for 1996 because $74,000 was incurred for a non-commercial
exploratory oil well. All exploration expenses reduce reported GAAP cash flow
from operations even though they are discretionary expenses; however, such
charges are added back for purposes of determining DCF which makes it more
comparable to cash flow reported by full cost accounting companies.
Impairments
A non-cash impairment loss of $243,000 in 1997 and $165,000 in 1996 was
recognized during the first nine months of each year because uneconomic Oklahoma
development wells completed during each year raised the question of whether
future net revenues for this entire pool would exceed the accrued undepreciated
costs. It was deemed advisable to accrue an impairment provision but should this
amount later prove to be excessive then depletion charges in future periods will
benefit, or vice versa. Likewise, the Louisiana Austin Chalk oil discovery,
although successful, brought into question the likelihood of developing certain
leaseholds in the AMI. Where annual renewal rentals either had already become
due or will become due before a reasonable production test period of the Morrow
#23-1H can be realized and a well promoted on these leaseholds, management
determined to write these off as a current charge as part of this exploratory
effort. Also included in this group were numerous small leaseholds where the
possibility of putting together a unit ready to be promoted was rather remote.
This charge recognized was $251,000 which brought the total to $494,000 non-cash
impairment for the third quarter.
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 lower during 1997's third quarter than in 1996. The average bank
interest rate paid this latest quarter was 7.2% which compares to 7.3% in 1996.
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Income Taxes
During the first nine months of 1997 the net deferred tax asset became a
net liability of $1,124,000 as a result of expected use of net operating loss
carryforwards. The net liability is comprised of $545,000 current deferred tax
asset and $1,669,000 long-term tax liability. The estimated utilization of
deferred tax assets was $1,151,000 during the nine months. The valuation
allowance has remained unchanged thus far in 1997. The effective tax rate for
1997 is 38%. See also Note 3 to the consolidated financial statements for
further explanation of income taxes.
Statement Pursuant to Safe Harbor Provision of the Private
Securities Litigation Reform Act of 1995
This report may contain certain "forward-looking statements" that have
been based on imprecise assumptions with regard to production levels, price
realizations, and expenditures for exploration and development and anticipated
results therefrom. Such statements are subject to risks and uncertainties that
could cause actual results to differ materially from those expressed herein or
implied by such statements.
26
<PAGE>
PART II - OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Management is unaware of any asserted or unasserted claims or assessments
against the Company which would materially affect the Company's future financial
position or results of operations.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
11 - Computation of per share earnings
27 - Financial data schedule
(b) Reports on Form 8-K
None
27
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COLUMBUS ENERGY CORP.
(Registrant)
DATE: October 14, 1997 /s/ Harry A.Trueblood, Jr.
---------------- ---------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 14, 1997 /s/ Ronald H.Beck
----------------- -----------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
28
<PAGE>
Commission File No. 1-9872
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBIT
TO
FORM 10-Q
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED AUGUST 31, 1997
COLUMBUS ENERGY CORP.
(Exact Name of Registrant)
1660 Lincoln Street
Denver, Colorado 80264
(Address of Principal Executive Office)
EXHIBIT 11
COLUMBUS ENERGY CORP.
Statement of Computation of Per Share Earnings
(Unaudited)
(In Thousands Except Per Share Data)
Nine Months Three Months
Ended August 31, Ended August 31,
---------------- ----------------
1997 1996 1997 1996
---- ---- ---- ----
Primary:
Based on weighted average
shares outstanding including
the effect of common stock
equivalents:
Weighted average shares
outstanding: 3,918 3,811 3,890 3,811
Incremental shares attributable
to dilutive stock options and
warrants outstanding based on
average market price during the
period calculated using the
treasury stock method 74 43 84 103
------ ------ ------ ------
Total average common and
common equivalent shares 3,992 3,854 3,974 3,914
====== ====== ====== ======
Net earnings $2,099 $1,539 $ 535 $ 456
====== ====== ====== ======
Earnings per share $ .53 $ .40 $ .13 $ .12
====== ====== ====== ======
Note:Fully diluted incremental shares for the nine months were 92,000 and
64,000 with total average common and common share equivalent shares
4,010,000 and 3,875,000 in 1997 and 1996, respectively.
Fully diluted incremental shares for the three months were 84,000 and
158,000 with total average common and common share equivalent shares
3,974,000 and 3,969,000 in 1997 and 1996, respectively.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
The Consolidated Balance Sheet As Of August 31, 1997 And The
Consolidated Statement Of Income For The Nine Months Ended
August 31, 1997.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> NOV-30-1997
<PERIOD-START> DEC-01-1996
<PERIOD-END> AUG-31-1997
<EXCHANGE-RATE> 1
<CASH> 1,232
<SECURITIES> 0
<RECEIVABLES> 3,707
<ALLOWANCES> 116
<INVENTORY> 248
<CURRENT-ASSETS> 5,658
<PP&E> 36,391
<DEPRECIATION> 15,267
<TOTAL-ASSETS> 26,782
<CURRENT-LIABILITIES> 4,292
<BONDS> 0
0
0
<COMMON> 889
<OTHER-SE> 16,732
<TOTAL-LIABILITY-AND-EQUITY> 26,782
<SALES> 9,919
<TOTAL-REVENUES> 10,922
<CGS> 2,323
<TOTAL-COSTS> 7,431
<OTHER-EXPENSES> (5)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 111
<INCOME-PRETAX> 3,385
<INCOME-TAX> 1,286
<INCOME-CONTINUING> 2,099
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,099
<EPS-PRIMARY> .54
<EPS-DILUTED> .54
<FN>
<F1>
Five-For-Four stocksplit May 27, 1997; Prior financial data schedules have not
been restated for this split.
</FN>
</TABLE>
