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, 2000
-----------------------
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: 001-9872
----------------------
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
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(Address of principal executive offices) (Zip Code)
(303) 861-5252
---------------------------------------------------
(Registrant's telephone number, including area code)
Not Applicable
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(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 6, 2000
---------------------------- ------------------------------
Common stock, $.20 par value 3,760,743
<PAGE>
COLUMBUS ENERGY CORP.
INDEX
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
August 31, 2000 and
November 30, 1999 3
Consolidated Statements of Operations -
Three Months and Nine Months Ended
August 31, 2000 and 1999 5
Consolidated Statement of
Stockholders' Equity -
Nine Months Ended August 31, 2000 6
Consolidated Statements of Cash Flows -
Nine Months Ended August 31, 2000
and 1999 7
Notes to the Consolidated Financial
Statements 9
Item 2. Management's Discussion and Analysis
of Financial Condition and
Results of Operations 15
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 27
Item 2. Not Applicable
Item 3. Quantitative and Qualitative Disclosure
About Market Risk 27
Items 4 and 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
<TABLE>
<CAPTION>
August 31, November 30,
2000 1999
----------- --------
(unaudited)
(in thousands)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 2,455 $ 1,850
Accounts receivable:
Joint interest partners 1,058 1,780
Oil and gas sales 2,195 1,501
Allowance for doubtful accounts (101) (116)
Deferred income taxes (Note 3) 60 200
Inventory of oil field equipment,
at lower of average cost or market 81 106
Other 50 80
------- -------
Total current assets 5,798 5,401
------- -------
Deferred income taxes (Note 3) 570 937
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 38,166 36,862
Other property and equipment 1,884 1,836
------- -------
40,050 38,698
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (24,895) (22,506)
------- -------
Net property and equipment 15,155 16,192
------- -------
$ 21,523 $ 22,530
======= =======
</TABLE>
(continued)
3
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
<TABLE>
<CAPTION>
August 31, November 30,
2000 1999
----------- --------
(unaudited)
(in thousands)
<S> <C> <C>
Current liabilities:
Accounts payable $ 1,933 $ 2,352
Undistributed oil and gas
production receipts 547 386
Accrued production and property taxes 474 738
Prepayments from joint interest owners 196 200
Accrued expenses 499 494
Income taxes payable (Note 3) 6 30
Other 2 32
------ ------
Total current liabilities 3,657 4,232
------ ------
Long-term bank debt (Note 2) 4,400 5,500
Commitments and contingent liabilities
(Notes 4, 5 and 9)
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
4,658,777 in 2000, and 4,645,303 in 1999
(outstanding 3,753,868 in 2000 and
3,800,558 in 1999) 932 929
Additional paid-in capital 20,139 20,069
Accumulated deficit (1,721) (2,655)
------ ------
19,350 18,343
Less: Treasury stock at cost
904,909 shares in 2000 and
844,745 shares in 1999 (5,884) (5,545)
------ ------
Total stockholders' equity 13,466 12,798
------ ------
$ 21,523 $ 22,530
====== ======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended Three Months Ended
August 31, August 31,
----------------- ------------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands, except per share data)
Revenues:
Oil and gas sales $10,742 $ 7,064 $ 4,671 $ 2,760
Operating and management
services 1,035 1,025 342 353
Interest and other income 114 70 45 23
------- -------- -------- -------
Total revenues 11,891 8,159 5,058 3,136
------- -------- -------- -------
Costs and expenses:
Lease operating expenses 1,566 1,357 544 514
Property and production taxes 995 741 410 242
Operating and management
services 598 693 164 220
General and administrative 1,217 1,075 340 299
Depreciation, depletion and
amortization 2,414 2,571 932 847
Impairments 500 503 500 -
Exploration expense 1,940 971 250 627
Litigation expense 380 41 13 24
Advisory fees 490 - 371 -
-------- -------- -------- -------
Total costs and expenses 10,100 7,952 3,524 2,773
-------- -------- -------- -------
Operating income 1,791 207 1,534 363
-------- -------- -------- -------
Other expenses (income):
Interest 325 273 108 98
Other 7 4 7 1
------- ------- -------- -------
332 277 115 99
------- ------- -------- -------
Earnings (loss) before
income taxes 1,459 (70) 1,419 264
Provision (benefit) for income
taxes (Note 3) 525 (27) 511 100
------- -------- ------- -------
Net earnings (loss) $ 934 $ (43) $ 908 $ 164
======= ======== ======= =======
Earnings (loss) per share (Note 7):
Basic $ .25 $ (.01) $ .24 $ .04
======= ======== ======== =======
Diluted $ .25 $ (.01) $ .24 $ .04
======= ======== ======== =======
Weighted average number of
common shares and common
equivalent shares
outstanding:
Basic 3,757 3,920 3,749 3,870
======= ======== ======= =======
Diluted 3,764 3,920 3,784 3,873
======= ======== ======= =======
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, 2000
(Unaudited)
<TABLE>
<CAPTION>
Common Stock Additional Treasury Stock
-------------------------- Paid-in Accumulated ---------------------
Shares Amount Capital Deficit Shares Amount
------------- ----------- ---------- ----------- ---------- -------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1999 4,645,303 $ 929 $20,069 $(2,655) 844,745 $(5,545)
Exercise of employee
stock options 2,200 1 9 - - -
Purchase of shares - - - - 63,000 (358)
Shares issued for Stock
Purchase Plan 11,274 2 61 - (2,836) 19
Net earnings - - - 934 - -
--------- ------ ------- ------- ------- ------
Balances,
August 31, 2000 4,658,777 $ 932 $20,139 $(1,721) 904,909 $(5,884)
========= ====== ======= ======= ======= ======
</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,
-----------------------
2000 1999
------ -----
(in thousands)
Net earnings (loss) $ 934 $ (43)
Adjustments to reconcile net earnings
(loss)to net cash provided by operating
activities:
Depreciation, depletion, and
amortization 2,414 2,571
Impairments 500 503
Deferred income tax provision (benefit) 507 (81)
Exploration expense, noncash portion - 80
Other 45 108
Net change in operating assets and
liabilities (561) (630)
-------- -------
Net cash provided by
operating activities 3,839 2,508
-------- -------
Cash flows from investing activities:
Proceeds from sale of assets 66 -
Additions to oil and gas properties (1,866) (2,487)
Additions to other assets (49) (11)
-------- -------
Net cash used in
investing activities (1,849) (2,498)
-------- -------
Cash flows from financing activities:
Proceeds from long-term debt 300 1,100
Reduction in long-term debt (1,400) (400)
Proceeds from issuance of
common stock 73 161
Purchase of treasury stock (358) (1,471)
-------- -------
Net cash used in financing
activities (1,385) (610)
-------- -------
Net increase (decrease) in cash and
cash equivalents 605 (600)
Cash and cash equivalents at
beginning of period 1,850 2,003
------ -------
Cash and cash equivalents at
end of period $ 2,455 $ 1,403
====== =======
(continued)
7
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
(Unaudited)
Nine Months Ended August 31,
-----------------------
2000 1999
------ -----
(in thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest $ 329 $ 271
====== =======
Income taxes, net of refunds $ 42 $ 28
====== =======
Supplemental disclosure of non-cash investing
and financing activities:
Non-cash compensation expense
related to common stock $ 44 $ 103
====== =======
The accompanying notes are an integral part of these consolidated financial
statements.
8
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) BASIS OF PRESENTATION
The accompanying consolidated financial statements include the
accounts of Columbus Energy Corp. ("Columbus") and its wholly-owned
subsidiaries, Columbus Gas Services, Inc. ("CGSI") and Columbus Texas, Inc.
("Texas"). All significant intercompany balances have been eliminated in
consolidation. The term "Company" as used herein includes Columbus and its
subsidiaries.
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, 2000 and November 30, 1999, 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.
The accounting policies followed by the Company are set forth in Note 2 to
the Company's consolidated financial statements in the Annual Report on Form
10-K for the year ended November 30, 1999. These accounting policies and other
footnote disclosures previously made have been omitted in this report so long as
the interim information presented is not misleading. These quarterly financial
statements should be read in conjunction with the consolidated financial
statements and notes included in the 1999 Form 10-K.
(2) LONG-TERM DEBT
The Company has a credit agreement with Wells Fargo Bank West, National
Association ("Bank"), formerly known as Norwest Bank Denver, N.A., that was
amended on June 30, 2000 to extend the revolving period to July 1, 2002 when it
entirely converts to an amortizing term loan which matures July 1, 2006. The
credit is collateralized by a first lien on oil and gas properties. The interest
rate options are the Bank's prime rate or LIBOR plus 1.50%.
The borrowing base is limited to $10,000,000 and subject to semi-annual
redetermination for any increase or decrease. At August 31, 2000 outstanding
borrowings on the revolving line of credit were $4,400,000 and the unused
borrowing base available was $5,600,000. A commitment fee of 1/4 of 1% for any
unused portion of the amount which is the difference between the borrowing base
and the outstanding borrowings is payable quarterly.
9
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
(3) INCOME TAXES
The provision (benefit) for income taxes consists of the following (in
thousands):
Nine Months Ended August 31,
----------------------------
2000 1999
---- ----
Current:
Federal $ 3 $ 25
State 15 29
----- -----
18 54
----- -----
Deferred:
Federal 487 (84)
Use of loss carryforwards - 6
State 20 (3)
----- -----
507 (81)
----- -----
Total income tax (benefit) expense $ 525 $ (27)
====== ======
During the nine months of fiscal 2000, 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
----------------------------------------
December 1, Operations/ August 31,
1999 Other 2000
-------- ----- -----
Deferred tax assets:
Pre-1987 loss carryforwards $ 440 $ - $ 440
Post-1987 loss carryforward 617 - 617
Percentage depletion
carryforwards 1,650 (4) 1,646
State income tax loss
carryforwards 124 - 124
Other 387 7 394
------ ------ ------
Total 3,218 3 3,221
Valuation allowance
(long-term) (1,286) - (1,286)
------- ------ ------
Deferred tax assets 1,932 3 1,935
------- ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (795) (510) (1,305)
------- ------ ------
Net tax asset (liability) $ 1,137 $ (507) $ 630
======= ======= =======
10
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
(4) LITIGATION
On May 4, 2000, Columbus was served with a complaint in a lawsuit styled
Fred E. Long and ENCO Exploration Company v. Columbus Energy Corp., Cause
B-00-1171-0-CV-B in the 156th Judicial District Court of Bee County, Texas. Fred
E. Long and his company, ENCO Exploration Company, have sued Columbus as
operator regarding the Long No. 4 well. Long/ENCO own a combined 25% working
interest. They contend that Columbus was negligent in its duty as operator to
drill a vertical hole without deviation at the location approved by the
participating working interest owners. They seek return of their proportionate
share of the drilling costs as damages, approximately $300,000. Columbus has
denied all of the Long/ENCO allegations and believes them to be without merit.
Discovery has not commenced.
(5) COMMITMENTS AND CONTINGENT LIABILITIES
The Company's natural gas and crude oil swaps are considered financial
instruments with off-balance sheet risk which are entered into in the normal
course of business to partially 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 has had in place a twelve month costless "collar" for 7,500
barrels of crude oil each month for the period September 1, 1999 through August
31, 2000. This "collar" was settled monthly against the calendar monthly average
price on the NYMEX with a $17.50 per barrel floor price and $22.25 per barrel
ceiling price. Columbus received or paid the difference below the floor or above
the ceiling that each monthly price averaged. During the third quarter and nine
months of fiscal 2000, oil sales were reduced by $192,000 and $441,000,
respectively, since average oil prices exceeded the $22.25 ceiling price each
month of those periods but no further reductions will occur during the balance
of fiscal 2000 because of the expiration of the collar.
The Company is not aware of any events of noncompliance in its operations
with environmental laws and regulations nor of any potentially material
contingencies related to environmental issues. Management cannot predict what
future environmental control problems may arise or what environmental
regulations and requirements might be enacted by jurisdictional authorities in
its various operational areas in future.
11
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED 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 was made by
Resources to Columbus for services provided by its officers and employees for
managing Resources in the past which effectively reduced Columbus' general and
administrative expense. Such reimbursement totaled $33,000 for the nine months
of 1999. On March 31, 1999, the agreement was terminated pursuant to a 90 day
notice period.
The Company has been a party to an arrangement with Mark Butler, geologist
and 50% owner of Trumark Production Company ("TPC"), during fiscal 1999 and 2000
whereby Mr. Butler would provide Columbus with 70 hours per month of geological
and geophysical consulting services (including related work station usage) at a
rate of $170 per hour. John B. Trueblood, son of Columbus' CEO Harry A.
Trueblood, Jr., owns the other 50% of TPC. The retainer fees paid to TPC were
$122,000 and $111,000 during nine months of 2000 and 1999, respectively.
12
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED 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,
---------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(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) $ 934 $ (43) $ 908 $ 164
===== ===== ===== =====
Shares (denominator):
Basic EPS 3,757 3,920 3,749 3,870
Effect of dilutive option shares 7 - 35 3
----- ----- ----- -----
Diluted EPS 3,764 3,920 3,784 3,873
===== ===== ===== =====
Per share amount:
Basic EPS $ .25 $ (.01) $ .24 $ .04
===== ===== ===== =====
Diluted EPS $ .25 $ (.01) $ .24 $ .04
===== ===== ===== =====
Number of shares not included in
dilutive EPS that would have been
antidilutive because exercise price
of options was greater than the
average market price of the common
shares 502 612 232 626
===== ===== ===== =====
(8) INDUSTRY SEGMENTS
The Company operates primarily in two business segments of (1) oil and gas
exploration and development and (2) providing services as an operator, manager
and gas marketing advisor.
13
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
Summarized financial information concerning the business segments is as
follows:
Nine Months Three Months
Ended August 31, Ended August 31,
---------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
Operating revenues from
unaffiliated services:
Oil and gas $10,751 $7,071 $4,675 $2,762
Services 1,140 1,088 383 374
------ ----- ------ ------
Total $11,891 $8,159 $5,058 $3,136
====== ===== ===== =====
Depreciation, depletion
and amortization:
Oil and gas $ 2,338 $2,528 $ 887 $ 833
Services 76 43 45 14
----- ----- ----- -----
Total $ 2,414 $2,571 $ 932 $ 847
====== ===== ===== =====
Operating income (loss):
Oil and Gas $ 3,412 $ 930 $2,085 $ 523
Services 86 351 160 138
General corporate
expense (1,707) (1,074) (711) (298)
------ ----- ----- -----
Total operating income 1,791 207 1,534 363
Interest expense and other (332) (277) (115) (99)
------ ----- ----- -----
Earnings (loss) before
income taxes $ 1,459 $ (70) $1,419 $ 264
====== ===== ===== =====
(9) MERGER AGREEMENT
Columbus and Key Production Company, Inc. (NYSE:KP) jointly announced on
August 29, 2000 that Key has agreed to acquire all of the outstanding common
stock of Columbus. Under the terms of the executed merger agreement Columbus'
shareholders will receive 0.355 of a share of Key common stock for each Columbus
share in a tax-free reorganization subject to a favorable Columbus shareholder
vote. Columbus expects to hold a special sharehold ers' meeting for that purpose
during November 2000 provided the SEC's review of the proxy statement/prospectus
is completed during October, 2000. The Board of Directors of both companies have
unanimously approved the transaction.
14
<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
As previously announced in February 2000 and reported in our Form 10-Q
for the quarter ended May 31, 2000, Arthur Andersen LLP's Global Energy
Corporate Finance team was selected to assist directors to explore various
strategic alternatives that could maximize shareholder value. A merger agreement
with Key was executed on August 28, 2000 and, assuming shareholder approval, the
effective date is expected in late November 2000. Thereafter, Columbus will
continue as a wholly-owned subsidiary of Key.
During third quarter of 2000, liquidity was further strengthened as oil and
gas sales increased 69% over 1999's like period. The Company's natural gas
prices averaged 79% higher than 1999's third quarter while crude oil prices were
36% higher. There was increased natural gas production but this improvement was
partially offset by a decline in oil production.
Third quarter 2000 had a pre-tax, non-cash impairment loss of $500,000 and
exploration expenses of $250,000 which reduced net earnings. Net earnings were
also adversely affected by a non- recurring charge for advisory fees and other
expenses connected with the auction process and completion of negotiations of
the terms of a proposed tax-free exchange of shares in a merger with Key.
Excluding the exploration expense, those other unusual charges amounted to a
reduction (after tax) of net earnings by $557,000, or $.15 per share. Despite
that reduction, quarterly net earnings for 2000's third quarter attained the
second highest ever of $908,000, or $0.24 per share, which compares with last
year's quarter of $164,000, or $0.04 per share.
Stockholders' equity as of the end of 2000's third quarter increased to
$13,466,000 from $12,798,000 at November 30, 1999 even after the repurchase of
63,000 treasury shares for $358,000. Also, working capital at August 31, 2000
had risen to $2,141,000 from $1,169,000 at the end of fiscal 1999.
This positive working capital combined with the Company's greatly increased
cash flow is expected to provide considerably more than the required funds for
the remainder of fiscal 2000's capital expenditure program. It is expected that
excess cash flow will be utilized to reduce bank debt. The unused portion of the
$10,000,000 bank credit facility has previously been targeted by management for
acquisitions of oil and gas properties, but can be used for any legal corporate
purpose.
15
<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 can
fluctuate widely depending on the scope of such activities. Net cash provided by
operating activities was $3,839,000 for the nine months of 2000, which compares
with $2,508,000 provided by operating activities for the same period last year.
GAAP defined operating cash flow for the nine months of 2000 was adversely
affected by the unusually large first quarter expenses attributed to exploratory
dry holes primarily located in the El Squared Prospect near Beeville, Texas.
As regularly noted in prior reports, management places greater reliance
upon an important alternative method of computing cash flow which is generally
known as Discretionary Cash Flow ("DCF"). DCF is not in accordance with GAAP but
is commonly used in the industry as this method calculates cash flow before
working capital changes or deduction of exploration expenses since the latter
can be increased or decreased at management's discretion. DCF is often used by
successful efforts companies to compare their cash flow results with those
independent energy companies who use the full cost accounting method whereby
exploration expenses are capitalized and do not immediately adversely affect
either operating cash flow or net earnings. Columbus' DCF for the nine months of
fiscal 2000 was $6,340,000 up 57% from 1999's similar period of $4,029,000. DCF
increased during third quarter of 2000 to $3,105,000, a new quarterly record and
up substantially from the $1,729,000 reported for the second quarter of 2000. As
discussed below in "Results of Operations," cash flow generated by the
significant production increase from a new well will not be repeated during the
fourth quarter because Columbus' interest was reduced following payout that
occurred during August. DCF is calculated without debt retirement being
considered. However, in Columbus' case this is not important since the existing
bank debt requires no principal payments before August 1, 2002 and is expected
to be eliminated before that date. Interest expense has already been deducted
before arriving at DCF.
16
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Management notes in each of its public filings and reports its strong
exception to the Statement of Financial Accounting Standards No. 95 as it
applies to Columbus which directs that operating cash flow must only be
determined after consideration of working capital changes. Management believes
such a requirement by GAAP ignores entirely the significant impact that the
timing of income received for, and expenses incurred on behalf of, third party
owners in properties may have on working capital. This is particularly
significant where Columbus owns only a small working interest but is the
operator of several properties.
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 nine months of 2000 and 1999 GAAP cash flow was materially
lower than DCF.
When used, the Company's natural gas and crude oil swaps are considered
financial instruments with off-balance sheet risk. These are entered into in the
normal course of business to partially reduce its exposure to fluctuations in
the price of crude oil and natural gas and may involve elements of market and
credit risk in excess of the amount recognized in the balance sheets.
During the nine months of fiscal 2000 the Company partially hedged its
crude oil prices while the Company's natural gas revenues were fully exposed to
price fluctuations which fortunately were positive. The non-hedged portion of
our crude oil revenues were similarly exposed to price fluctuations which were
also positive.
The only hedge in existence during third quarter 2000 was a costless
"collar" for 7,500 barrels per month which expired August 31, 2000. This hedge
is more fully described in Note 5, "Commitments and Contingent Liabilities", in
the Notes to the Consolidated Financial statements.
At August 31, 2000, Columbus had outstanding bank borrowings of
$4,400,000 against its $10,000,000 line of credit with Wells Fargo Bank West,
N.A. which is collateralized by its oil and gas properties. On that same date,
the ratio of net long-term debt (debt less working capital) to total assets was
0.10. The outstanding debt used a LIBOR option with an average interest rate of
8.1%. Subsequent to the end of the third quarter and through October 6, 2000,
long-term debt was further reduced by $500,000 to $3,900,000. The net increase
(or decrease) in long-term debt directly affects cash flows from financing
activities as do the purchase of
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
treasury shares. For the Company's floating rate debt, interest rate changes
generally do not affect its fair market value but does impact future results of
operations and cash flows, assuming other factors remain constant. The carrying
amount of the Company's debt approximates its fair value.
The Company's Board of Directors has authorized over the last several years
the repurchase of common shares from the market at various "not to exceed" price
levels. As of August 31, 2000 a total of 60,384 shares remained unpurchased from
the most recent authorizations at a price not to exceed $6.00 per share but none
is expected to be purchased in light of current market price and the impending
merger with Key.
During nine months of 2000, capital expenditures actually incurred for oil
and gas properties totaled $1,895,000 (which amount excludes $1.9 million for
exploratory dry holes and other exploration expenses) and differs from the
capital expenditure shown in the Consolidated Statement of Cash Flows. The
latter also includes cash payments made during 2000 for 1999 expenditures which
had been incurred but not yet paid as of 1999's year end. Similarly, some
expenditures accrued during fiscal 2000's nine months period were not actually
paid until subsequent to the end of the period.
18
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
RESULTS OF OPERATIONS
Gross revenues increased by 61% over last year's third quarter and
operating income increased to $1,534,000 in the current quarter compared to
$363,000 last year. Other comparisons for the 2000 quarter and nine month
periods versus 1999 related to prices, production and oil and gas sales appear
in tabular form below.
During 2000's third quarter six gross wells (2.89 net WI) were drilled.
These included two (.30 net WI) gas development wells in Webb County, Texas, and
one (.92 net WI) gas development well located in Bee County, Texas. One (.34 net
WI) well in Oklahoma was an attempted extension in a horizontal hole drilled out
of an existing cased well bore but the Morrow oil reservoir encountered was
previously depleted and that zone in the lateral was abandoned. However, an
existing oil zone in the original well bore could be recompleted and is
currently producing about 10 barrels per day with no fracture stimulation. One
(1.00 net WI) other exploratory oil well was a successful recompletion as a new
zone discovery in an existing well. This was a "behind-the-pipe" Duperow zone in
a well located in Richland County, Montana which had not been considered
prospective. This zone initially raised production to in excess of 100 barrels
of crude oil per day and has apparently leveled out at approximately 50 barrels
per day. The Long #5 well in Bee County commenced production at about 700 Mcfd
in late July and has improved to 1,500 Mcfd following frac treatment. It is
currently producing approximately 1,300 Mcfd on a small choke. The BMT #15 (.26
net WI) in Webb County was completed but not hooked-up to a gas pipeline until
after the quarter's end. Its initial rate of 2,000 Mcfd and over 20 barrels of
condensate per day has leveled out at about 1,800 Mcfd and has not been
stimulated yet. The other Webb County well (.04 net WI) was connected in August
and is making approximately 1,400 Mcf per day. During the fourth quarter, the
production from these wells will help offset the decreased production to
Columbus' interest from the Hachar #36 following payout in August.
As highlighted in the second quarter report, the Hachar #36, in which
Columbus owns a 53.7% net revenue interest, until 200% of the well costs of the
well are recovered, was an outstanding gas well completed in the Lobo sand in
the Laredo field area. It was connected to a pipeline during May 2000 producing
at a rate in excess of 5,000,000 cubic feet of natural gas and 100 barrels of
condensate per day. This revenue from the Hachar #36 had a very large impact on
results for the third quarter by yielding $965,000 of net lease level income.
This is defined as revenue less operating costs and production taxes. Payout of
200% of costs of the well occurred in mid-August in three months and reduced
Columbus' monthly net revenue stream from over $300,000 to an estimated $25,000
in September at its current net revenue interest of 3.8%.
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Oil and Gas Revenues and Operating Costs
The following table shows comparative crude oil and natural gas
revenues, sales volumes, average prices and percentage changes between the
periods presented as follows:
<TABLE>
<CAPTION>
Third Quarter Nine Months
--------------------------------- --------------------------------
2000 1999 Change 2000 1999 Change
------ ------ ------ ---- ---- ------
<S> <C> <C> <C> <C> <C> <C>
Natural gas revenues M$ $3,627 $1,943 87 % 7,758 $ 5,261 47 %
Oil revenue M$ $1,044 $ 817 28 % $ 2,984 $ 1,803 66 %
Natural gas sales volumes:
Millions of cubic feet (MMCF) 799 765 4 % 2,228 2,451 (9)%
MCF/day 8,680 8,310 8,101 8,945
Oil sales volumes:
Barrels 41,854 44,434 (6)% 123,717 121,781 2 %
Barrels/day 455 483 450 444
Average price received:
Natural gas - $/MCF $ 4.54 $ 2.54 79 % $ 3.48 $ 2.15 62 %
Oil - $/BBL $24.96 $18.38 36 % $24.12 $14.80 63 %
</TABLE>
Natural gas revenues for the quarter increased by 87% over 1999's third
quarter due to 79% higher prices and 4% higher sales volumes. Similarly, the
nine month period for 2000 had 47% higher natural gas revenues due to 62% higher
prices partially offset by 9% lower sales volumes. Average gas prices have
improved steadily from depressed price levels experienced during the early part
of 1999 which reflected a prior warm winter and relatively high storage
inventory. This storage level has not been maintained throughout 2000 to date
because of this summer's strong demand for cooling load which has severely
restricted excess supply for storage refill. Disaster was averted by a warm
winter heating season in early 2000 but increased demand and lack of additional
supply for injection due to very limited excess gas capacity have caused prices
to exceed $5.00 per Mcf recently. Higher natural gas production during third
quarter 2000 compared with 1999 was not sufficient to overcome the decline in
production between comparable nine month periods. Normal production declines in
older wells due to depletion were not reversed by new production since there was
less exploratory drilling success than had been expected, there was reduced
inventory of new prospects or development locations available to drill, and the
effects from the lack of drilling in fiscal 1998 and 1999 because of the price
debacle brought about those low cash flow years.
Oil revenues for 2000's third quarter increased by 28% over the 1999
quarter because average prices rose by 36% although there were 6% lower sales
volumes. Comparative nine month's results show 66% greater oil revenues since
average prices were up 63% and sales volumes were up 2%. Oil revenues and
average prices for 2000 were impacted adversely by the crude oil collar. The
reduction amounted to $192,000 ($4.59 per barrel) for the third quarter and
$441,000 ($3.56 per barrel) for the nine months. Oil production has declined
20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
steadily for the past few years commensurate with a lack of development drilling
activity and no exploratory incentives in keeping with low crude oil prices and
lack of certainty of future improvement. During 1999's first half several oil
wells were temporarily shut-in due to those low crude oil prices and did not
resume production until later that year. One exploratory well searching for gas
did discover a flowing oil well in Harris County, Texas. This well was drilled
during fiscal 1998 but would not be connected to a gas line. It began production
flowing 200 barrels of oil per day with associated gas during June 1999.
Columbus' 19.5% working interest in that well did help improve crude oil
production during 1999 but only temporarily overcame the ongoing decline in
other wells which caused the reduction of third quarter 2000 oil volumes
compared to the prior year's quarter. Prices for crude oil have continued to
move upwards due to strong demand and a restrictive production program
instigated by OPEC which has not kept pace with that demand.
Columbus' third quarter sales volumes of natural gas averaged 8,680 Mcfd
while oil and liquids sales volumes were 464 barrels per day which equates to a
daily sales volume of 11,467 MCF equivalent (Mcfe). This compares with 1999's
third quarter rate of 11,245 Mcfe, a 2% increase. As stated before, this small
increase was attributable to increased sales volumes net to Columbus from the
Hachar #36 well which temporarily overcame the lack of new development wells
being drilled along with a lack of exploratory success at Columbus' El Squared
prospect. Production from the Hachar #36 and Lien #2 wells temporarily reversed
the decline in oil production but the fourth quarter of 2000 is expected to be
less than third quarter volumes. For comparative nine month's periods, average
daily sales volumes were 10,845 Mcfe in 2000 versus 11,646 Mcfe in 1999 and were
affected adversely for the aforementioned reasons.
Lease operating expenses for the third quarter and nine months of 2000 were
6% and 15% higher, respectively, than similar periods in 1999. Most of the
increase was in the Williston Basin in Montana and the Sralla Road field in
Texas where several wells had workover costs including repairs and replacements
of equipment. Periodic expensive workovers and replacement of downhole and
surface equipment on older wells is a normal occurrence. Also, several older
Williston Basin oil wells were shut-in during 1999's first half which accounts
for lower operating costs in that year. Lease operating costs on an Mcfe basis
were $0.52 in the third quarter of 2000 compared to $0.50 in 1999 while
operating costs as a percentage of revenues were 12% in 2000 versus 19% in 1999
with its lower prices but with reduced costs. For the nine month periods, lease
operating costs were $0.53 per Mcfe in 2000 and $0.43 in 1999 and lease
operating costs as a percentage of revenues were 15% in 2000 and 19% in 1999.
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Production and property taxes approximated 9% of revenues in the nine
months of 2000 and 10% in 1999. These taxes 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
most of the local jurisdiction's property taxes in Texas 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 operations and
services conducted on behalf of third parties which includes compressor
operations and salt water disposal facilities.
Operating and management services gross profit was as follows:
2000 1999
---- ----
Third quarter $178,000 $133,000
Nine months $437,000 $332,000
Operating revenues increased during 2000 partially due to Columbus' 5%
share of transportation revenues from a gas pipeline in the Sralla Road area of
Texas. Effective March 1, 2000, the Company no longer is serving as contract
operator for wells in the Berry R. Cox field in South Texas, which generated
$23,000 of profit during 2000's first quarter. Operating and management service
costs were less in 2000 due to fewer compressor repairs in Texas and lower costs
after payroll recoveries billed to others in the Williston Basin area.
Interest Income
Interest income is earned primarily from short-term invest ments whose
rates fluctuate with changes in the commercial paper rates and the prime rate.
Interest income increased in the third quarter of 2000 to $45,000 from $23,000
in 1999's third quarter because of a larger amount of investments resulting from
higher natural gas and crude oil prices and 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.
22
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
The Company's general and administrative expenses were as follows:
2000 1999
---- ----
Third quarter $ 340,000 $ 299,000
Nine months $1,217,000 $1,075,000
Nine month expenses exceeded last year's primarily due to cash bonuses of
$178,000 paid in May but there were no stock option grants. This compares with
1999 incentive bonuses of $80,000 ($58,000 non-cash) plus grants of stock
options to all officers. Also, as previously disclosed there was a total
phase-out of reimbursement for management services provided Resources during
1999. Salary increases were granted effective December 1, 1999 for non-officer
employees and officer salaries were increased May 1, 2000 after having been
frozen at prior year levels during 1999. However, total officer and directors'
expense was reduced because there was one less officer and one less director
during 2000. Expenses accrued for vacation and retirement pay were higher during
both the third quarter and nine month periods this year compared to 1999 due to
a higher salary base. Medical claims under the Company's self-insured plan were
higher for 2000's third quarter and nine months. Office rent was about the same
during third quarter in 2000 compared to 1999 as a result of a sublease of a
portion of the leased space but for the nine months period, rental expense and
parking was higher due to an increase in the monthly rate. Both the third
quarter and nine month periods' outside contract and professional services were
lower in fiscal 2000 versus 1999.
Unusual expenses were incurred during third quarter and nine months which
relate to exploring various strategic alternatives for the Company by use of
financial advisors as well as subsequent related merger negotiation costs. These
fees totaled $371,000 for the third quarter and appear under expenses as
"Advisory fees".
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 field. This expense is not only
directly related to the level of production, but is also dependent upon past
costs to find, develop, and recover related reserves in each of the fields.
Depreciation and amortization of office equipment and computer software is also
included in the total charge.
Charges for this expense item increased from 1999's third quarter due to
updated estimates of proved oil and gas reserves in connection with the merger
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
and its third quarter review. Estimates by independent engineers show that
proved reserves as of June 30, 2000 totaled 21.2 Bcfe, down from 26.1 Bcfe at
the end of the Company's previous fiscal year (November 30, 1999). During the
first seven months of fiscal year 2000, Columbus produced 2.3 Bcfe and downward
reserve adjustments totaled 3.6 Bcfe which were partially offset by a 1.0 Bcfe
increase due to higher prices. The major reserve adjustments resulted from
Columbus receiving information that other operators and participants in two
properties had determined not to proceed with drilling or recompletion of new or
existing wells. Recent drilling activity and performance of wells as well as an
evaluation of certain technical data, also contributed to those decisions. The
depletion rate for third quarter 2000 was $.83 per Mcfe compared to $.79 per
Mcfe for that like period of 1999. For the nine month periods depletion expense
decreased as a result of decreased production from fields having higher rates
and increased production from the Laredo area where there is a lower depletion
rate. The depletion rate per Mcfe was $.77 for this period during 2000 compared
to $.78 per Mcfe in 1999.
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 including associated
leaseholds. 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. 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 which capitalize such costs.
Exploration charges of $250,000 for 2000's third quarter were down from
1999's $627,000 and included $186,000 related to the drilling of a horizontal
well in Oklahoma. A total of $531,000 was expensed last year in connection with
deepening an exploratory well in the El Squared prospect which did not find any
proved reserves along with $30,000 for seismic interpretation costs.
Nine months of fiscal 2000 exploration charges of $1,940,000 were up
significantly over 1999's. Most of these charges ($1,371,000) were incurred
during the sidetrack and testing phase of the Long #4 and the initiation of a
sidetrack of the Long #3 as well as for the subsequent abandonments of those
wells. Also included was $196,000 for recompletion and abandonment costs for a
24
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
90%-owned exploratory well in Montana. In addition to 1999's third quarter
expense described above, a total of $233,000 was expensed for three exploratory
dry holes and $47,000 for undeveloped leases dropped as a result of an offset
dry hole being drilled during that nine month period.
Whenever a company who uses the successful efforts method of accounting is
involved in an exploratory program which represents a significant part of its
budget, that company is automatically subjected to the risk that its net
earnings for any given quarter or year will be impacted negatively by wildcat
dry holes. Shareholders have been previously forewarned that net earnings and
GAAP cash flow for a given period may not be truly indicative of the Company's
operational activity. This is why management has suggested that shareholders may
wish to follow management's program of placing more emphasis on DCF from period
to period while essentially ignoring net earnings results. Comparing Columbus'
results with net earnings or cash flows of companies who use the full cost
accounting method is unrealistic since they capitalize exploratory drilling and
seismic costs as well as other costs related to such activity.
Impairments
As an outgrowth of a revised technical evaluation of Columbus' ability to
economically recomplete the updip lateral's proved reserves originally drilled
in its Morrow #23-1H well in Louisiana, Columbus' co-operator participant
indicated he was no longer interested in attempting to recover these reserves.
Therefore, a non-cash impairment expense of $500,000 during the third quarter
was recorded as the Company was unwilling to attempt such an operational expense
by itself.
Last year at the end of the second quarter, there was a pre- tax, non-cash
impairment loss of $503,000 as a result of reduced proved undeveloped reserves.
The improvement in crude oil prices up to that time was considered insufficient
to justify restoration of proved undeveloped reserves in one of the Williston
Basin's fields because the indicated return on new investments would be
unsatisfactory. Therefore, any restoration of undeveloped reserves was deferred
and the shortfall of $253,000 between remaining book value of the pool and the
then current fair market value of reserves was recognized as a charge.
Elsewhere, an unexpected influx of water in natural gas wells in a shallow gas
property in Jim Wells County, Texas brought about premature abandonment of the
producing zones with related reserves. This generated a pre-tax, non-cash
impairment of $250,000.
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Litigation Expense
Almost all of the unusually high litigation expense for the nine months
period is related to the successful defense of the Maris E. Penn, et al lawsuit
described in previous quarters. A small amount of legal expenses in the third
quarter are the result of the Fred E. Long, et al lawsuit described in Note 4 of
the Notes to the Financial Statements.
Interest Expense
Interest expense varies in direct proportion to the amount of bank debt and
the level of bank interest rates. The average level of bank debt outstanding has
been higher during the 2000's first and second quarters than in 1999. The
average bank interest rate paid during the third quarter was 8.2% which compares
to 6.6% in 1999. For the nine month periods average interest rates were 7.8% in
2000 and 6.6% in 1999.
Income Taxes
During the nine months of 2000, the net deferred tax asset decreased to
$630,000. The asset is comprised of a $60,000 current portion and $570,000
long-term asset. The estimated decrease in deferred tax assets was $507,000
during that period. Thus far in 2000, the valuation allowance has remained
unchanged and the effective tax rate is 36%. See 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. See Note (4) of the Notes to the Financial
Statements regarding a lawsuit styled Fred E. Long and ENCO Exploration Company
v. Columbus Energy Corp. filed in the 156th Judicial District Court of Bee
County, Texas, Cause No. B-00-1171-0-CV-B.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's exposure to interest rate risk and commodity price risk is
discussed in Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Liquidity and Capital Resources".
The Company has no exposure to foreign currency exchange rate risks or to any
other market risks.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 - Fourth Amendment of Credit Agreement dated
June 30, 2000 between Columbus Energy
Corp. and Wells Fargo Bank West, National
Association.
27 - Financial data schedule - August 31, 2000.
(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 12, 2000 /s/ Harry A. Trueblood, Jr.
----------------------------- ---------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 12, 2000 /s/ Ronald H. Beck
----------------------------- ------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
28
