UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended May 31, 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
- --------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
(303) 861-5252
--------------------------------------------------
(Registrant's telephone number, including area code)
Not Applicable
------------------------------------------------------
(Former name, former address and former fiscal year, if
changed since last report)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
---- ------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at July 12, 2000
- ----------------------------- ----------------------------
Common stock, $.20 par value 3,751,668
COLUMBUS ENERGY CORP.
INDEX
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
May 31, 2000 and
November 30, 1999 3
Consolidated Statements of Operations -
Three Months and Six Months Ended
May 31, 2000 and 1999 5
Consolidated Statement of
Stockholders' Equity -
Six Months Ended May 31, 2000 6
Consolidated Statements of Cash Flows -
Six Months Ended May 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
Item 4. Submission of Matters to a Vote of
Security Holders 27
Item 5. Not Applicable
Item 6. Exhibits and Reports
on Form 8-K 27
Signatures 28
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
May 31, November 30,
2000 1999
----------- ------------
(unaudited)
(in thousands)
Current assets:
Cash and cash equivalents $ 1,892 $ 1,850
Accounts receivable:
Joint interest partners 1,183 1,780
Oil and gas sales 1,667 1,501
Allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 3) 110 200
Inventory of oil field equipment,
at lower of average cost or market 84 106
Other 108 80
------- -------
Total current assets 4,928 5,401
------- -------
Deferred income taxes (Note 3) 1,025 937
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 37,455 36,862
Other property and equipment 1,844 1,836
------- -------
39,299 38,698
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (23,963) (22,506)
------- -------
Net property and equipment 15,336 16,192
------- -------
$ 21,289 $ 22,530
======== ========
(continued)
3
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
May 31, November 30,
2000 1999
----------- ------------
(unaudited)
(in thousands)
Current liabilities:
Accounts payable $ 2,069 $ 2,352
Undistributed oil and gas
production receipts 417 386
Accrued production and property taxes 385 738
Prepayments from joint interest owners 199 200
Accrued expenses 477 494
Income taxes payable (Note 3) 2 30
Other 36 32
------ ------
Total current liabilities 3,585 4,232
------ ------
Long-term bank debt (Note 2) 5,200 5,500
Commitments and contingent liabilities
(Notes 4 and 5)
Stockholders' equity:
Preferred stock authorized 5,000,000
shares, no par value, none issued - -
Common stock authorized 20,000,000
shares of $.20 par value; shares issued
4,650,748 in 2000, and 4,645,303 in 1999
(outstanding 3,744,374 in 2000 and
3,800,558 in 1999) 930 929
Additional paid-in capital 20,097 20,069
Accumulated deficit (2,629) (2,655)
------ ------
18,398 18,343
Less: Treasury stock at cost
906,374 shares in 2000 and
844,745 shares in 1999 (5,894) (5,545)
------ ------
Total stockholders' equity 12,504 12,798
------ ------
$ 21,289 $ 22,530
====== ======
The accompanying notes are an integral part of these consolidated financial
statements.
4
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Six Months Ended Three Months Ended
May 31, May 31,
----------------------- -------------------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands, except per share data)
Revenues:
Oil and gas sales $ 6,071 $ 4,304 $ 3,331 $ 2,271
Operating and management
services 693 672 323 336
Interest and other income 69 47 36 20
------- -------- -------- -------
Total revenues 6,833 5,023 3,690 2,627
------- -------- -------- -------
Costs and expenses:
Lease operating expenses 1,022 843 477 421
Property and production taxes 585 499 301 255
Operating and management
services 434 473 203 222
General and administrative 877 776 549 440
Depreciation, depletion and
amortization 1,482 1,724 731 834
Impairments - 503 - 503
Exploration expense 1,690 344 278 225
Litigation expense (Note 4) 367 17 209 13
Advisory fees 119 - 119 -
-------- -------- -------- -------
Total costs and expenses 6,576 5,179 2,867 2,913
-------- -------- -------- -------
Operating income (loss) 257 (156) 823 (286)
-------- -------- -------- --------
Other expenses (income):
Interest 217 175 110 91
Other - 3 - 2
------- --------- ------- -------
217 178 110 93
------- -------- -------- -------
Earnings (loss) before
income taxes 40 (334) 713 (379)
Provision (benefit) for income
taxes (Note 3) 14 (127) 243 (144)
------- -------- ------- --------
Net earnings (loss) $ 26 $ (207) $ 470 $ (235)
======= ======== ======= ========
Earnings (loss) per share (Note 7):
Basic $ .01 $ (.05) $ .13 $ (.06)
======= ======== ======= ========
Diluted $ .01 $ (.05) $ .13 $ (.06)
======= ======== ======= ========
Weighted average number of common shares and common equivalent shares
outstanding:
Basic 3,761 3,946 3,748 3,883
======= ======== ======= =======
Diluted 3,763 3,946 3,753 3,883
======= ======== ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
5
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Six Months Ended May 31, 2000
(Unaudited)
Common Stock Additional Treasury Stock
-------------------------- Paid-in Accumulated ---------------------
Shares Amount Capital Deficit Shares Amount
------------- ----------- ---------- ----------- ---------- -------
(dollar amounts in thousands)
Balances,
December 1, 1999 4,645,303 $ 929 $20,069 $(2,655) 844,745 $(5,545)
Purchase of shares - - - - 63,000 (358)
Shares issued for Stock
Purchase Plan 5,445 1 28 - (1,371) 9
Net earnings - - - 26 - -
--------- ------- ------- ------- ------- ------
Balances,
May 31, 2000 4,650,748 $ 930 $20,097 $(2,629) 906,374 $(5,894)
========= ======= ======= ======= ======= ======
The accompanying notes are an integral part of these consolidated financial
statements.
6
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended May 31,
------------------------
2000 1999
------ -----
(in thousands)
Net earnings (loss) $ 26 $ (207)
Adjustments to reconcile net earnings (loss)
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization 1,482 1,724
Impairments - 503
Deferred income tax provision (benefit) 2 (168)
Exploration expense, noncash portion - 80
Other 35 84
Net change in operating assets and
liabilities (369) (726)
-------- -------
Net cash provided by
operating activities 1,176 1,290
-------- -------
Cash flows from investing activities:
Proceeds from sale of assets 66 -
Additions to oil and gas properties (563) (1,641)
Additions to other assets (9) (11)
-------- -------
Net cash used in
investing activities (506) (1,652)
-------- -------
Cash flows from financing activities:
Proceeds from long-term debt 300 900
Reduction in long-term debt (600) (300)
Proceeds from issuance of
common stock 29 128
Purchase of treasury stock (357) (1,421)
-------- -------
Net cash used in financing
activities (628) (693)
-------- -------
Net increase (decrease) in cash and
cash equivalents 42 (1,055)
Cash and cash equivalents at
beginning of period 1,850 2,003
------ -------
Cash and cash equivalents at
end of period $ 1,892 $ 948
====== =======
(continued)
7
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
(Unaudited)
Six Months Ended May 31,
------------------------
2000 1999
------ -----
(in thousands)
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest $ 218 $ 174
====== =======
Income taxes, net of refunds $ 40 $ 21
====== =======
Supplemental disclosure of non-cash investing and financing activities:
Non-cash compensation expense
related to common stock $ 35 $ 81
====== =======
The accompanying notes are an integral part of these consolidated financial
statements.
8
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 May 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 Norwest Bank Denver, N.A. ("Bank")
that was amended on May 12, 1999 to extend the revolving period to July 1, 2001
when it entirely converts to an amortizing term loan which matures July 1, 2005.
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 May 31, 2000 outstanding
borrowings on the revolving line of credit were $5,200,000 and the unused
borrowing base available was $4,800,000. 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
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):
Six Months Ended May 31,
------------------------
2000 1999
---- ----
Current:
Federal $ 2 $ 17
State 10 24
----- -----
12 41
----- -----
Deferred:
Federal 2 (165)
Use of loss carryforwards - 4
State - (7)
----- -----
2 (168)
----- -----
Total income tax (benefit) expense $ 14 $ (127)
===== ======
During the six 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/ May 31,
1999 Other 2000
-------- ----------- ------
Deferred tax assets:
Pre-1987 loss carryforwards $ 440 $ - $ 440
Post-1987 loss carryforward 617 - 617
Percentage depletion
carryforwards 1,650 - 1,650
State income tax loss
carryforwards 124 - 124
Other 387 2 389
------- ------ ------
Total 3,218 2 3,220
Valuation allowance
(long-term) (1,286) - (1,286)
------- ------ ------
Deferred tax assets 1,932 2 1,934
------- ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (795) (4) (799)
-------- ------ ------
Net tax asset (liability) $ 1,137 $ (2) $ 1,135
======== ====== =======
10
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
(4) LITIGATION
On October 7, 1998, Columbus was served with a complaint in a lawsuit
styled Maris E. Penn, Michael Mattalino, Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98-44940 in the 55th District Court of
Harris County, Texas. The plaintiffs were parties to a September 1994 settlement
agreement that provided for the conveyance of overriding royalty interests in
leases acquired by Columbus in certain portions of Harris County. Plaintiffs
claimed Columbus was also obligated under the settlement agreement but failed to
acquire and develop all leases available within a described portion of Harris
County as a reasonably prudent operator. Plaintiffs claimed damages based upon
their alleged right to a 3% overriding royalty interest in leases drilled by
third parties within that described area. Columbus denied those allegations.
A five-day trial which began on May 22, 2000 resulted in the jury
returning a verdict in favor of Columbus. Specifically, the jury found that
Columbus had not breached its obligations to act as a reasonably prudent
operator in pursuing development of properties located within the area of mutual
interest. The remaining step toward closing the case is for the Court to enter
the verdict as a judgment. While the Plaintiffs have the right to appeal the
judgment to the Court of Appeals in Houston it is not anticipated that will
occur.
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 regarding
the Long No. 4 well. Long/ENCO combined own a 25% working interest and contend
that the Long No. 4 was not drilled 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
contests the Long/ENCO allegations.
(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
11
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
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's current crude oil hedge outstanding is a twelve month
costless "collar" for 7,500 barrels per month for the period September 1, 1999
through August 31, 2000. This "collar" is settled monthly against the calendar
monthly average price on the NYMEX with a $17.50 per barrel floor and $22.25 per
barrel ceiling below or above which such monthly average Columbus receives or
pays the difference. This increases or reduces oil revenues monthly if such
occurs. During the second quarter and six months of fiscal 2000, oil sales were
reduced by $131,000 and $249,000, respec tively, since oil prices exceeded the
$22.25 ceiling price each month during the periods. Subsequently, for the month
of June 2000, oil sales will be reduced by $70,000. If during the remaining
period of July and August 2000 NYMEX prices equal the prices quoted as of June
30, 2000 as an average for each of those months, the settlement value would be
$138,000 and would further reduce crude oil sales by such an amount.
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.
(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 $32,000 for the first six
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
12
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
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 $86,000 and $76,000 during first half 2000 and 1999, respectively.
(7) EARNINGS PER SHARE
The following table provides a reconciliation of basic and diluted
earnings per share (EPS):
Six Months Three Months
Ended May 31, Ended May 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) $ 26 $ (207) $ 470 $ (235)
===== ===== ===== =====
Shares (denominator):
Basic EPS 3,761 3,946 3,748 3,883
Effect of dilutive option shares 2 - 5 -
----- ----- ----- -----
Diluted EPS 3,763 3,946 3,753 3,883
===== ===== ===== =====
Per share amount:
Basic EPS $ .01 $ (.05) $ .13 $ (.06)
===== ===== ===== =====
Diluted EPS $ .01 $ (.05) $ .13 $ (.06)
===== ===== ===== =====
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 507 460 507 532
===== ===== ===== =====
13
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(Unaudited)
(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.
Summarized financial information concerning the business segments is as
follows:
Six Months Three Months
Ended May 31, Ended May 31,
------------- -------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
Operating revenues from
unaffiliated services:
Oil and gas $6,076 $4,309 $3,333 $2,251
Services 757 714 357 376
------ ------ ------ ------
Total $6,833 $5,023 $3,690 $2,627
===== ===== ===== =====
Depreciation, depletion
and amortization:
Oil and gas $1,451 $1,695 $ 716 $ 820
Services 31 29 15 14
----- ----- ----- -----
Total $1,482 $1,724 $ 731 $ 834
===== ===== ===== =====
Operating income (loss):
Oil and Gas $1,327 $ 425 $1,561 $ 27
Services (74) 195 (70) 127
General corporate
expense (996) (776) (668) (440)
------ ----- ----- -----
Total operating income 257 (156) 823 (286)
Interest expense and other (217) (178) (110) (93)
------ ----- ----- -----
Earnings (loss) before
income taxes $ 40 $ (334) $ 713 $ (379)
===== ===== ===== =====
14
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, Arthur Andersen LLP's Global
Energy Corporate Finance team was selected to assist Directors to explore
various strategic alternatives that could maximize shareholder value.
Shareholders had previously been informed that several major shareholders had
expressed a preference for a tax free swap versus a cash sale but the Board of
Directors indicated it planned to consider those offers submitted following an
appropriate review by its financial advisors. The advisory team prepared a
detailed informational report about Columbus' assets as well as its field,
administrative and technical personnel and this was made available for all
interested parties who signed a confidentiality agreement. Such parties were
requested to submit an indication of their interest in an acquisition which
procedure was designed to narrow prospective suitors to a manageable number.
Following discussions and screening of submitted proposals by the financial
advisors with the Board of Directors, the more likely acquirors were invited to
visit a data room. Completion of a transaction by early fall, while desirable,
is certainly not set in concrete nor is there any assurance that a satisfactory
agreement will be forthcoming from this undertaking. Based on the current
activity level of mergers and acquisitions in the domestic energy industry,
management is optimistic that a deal might be consummated with one of those
potential acquirors.
During second quarter of 2000, the liquidity outlook improved as oil
and gas sales increased almost 50% over 1999's period. The Company's natural gas
prices averaged 57% higher than 1999's second quarter while crude oil prices
were 59% higher along with increased crude oil production. This improvement was
partially offset by declines in natural gas production and the crude oil hedge.
Second quarter 2000 had higher exploration expenses of $278,000 which,
after being tax effected, reduced earnings by $183,000, or $.05 per share. Also,
net earnings were adversely affected by unusual, non-recurring charges such as
advisory fees and other expenses connected with exploring strategic alternatives
as well as the litigation expenses connected with the successful defense of the
Mattalino, et al lawsuit. Net earnings for the second quarter 2000, despite
those charges, still reached $470,000, or $0.13 per share, compared with last
year's quarter net loss of $235,000, or $0.06 per share.
15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Stockholders' equity as of the end of 2000's first six months decreased
to $12,504,000 from $12,798,000 at November 30, 1999 primarily the result of a
repurchase of 63,000 treasury shares.
Positive working capital combined with the Company's anticipated cash
flow is expected to provide more than sufficient funds for the fiscal 2000
capital expenditure program. 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. It is expected
that excess cash flow will be utilized to reduce bank debt.
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. Net cash provided by operating activities was $1,176,000
for the first six months of 2000, which compares with $1,290,000 provided by
operating activities for the same period last year. GAAP defined operating cash
flow for the six months of 2000 was adversely affected by the unusually large
first quarter expenses attributed to exploratory dry holes 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 first
six months of fiscal 2000 was $3,235,000 up 42% from 1999's similar period of
$2,280,000 when more shares were outstanding. DCF continued to improve during
second quarter of 2000 to $1,729,000 from the $1,506,000 realized during the
first quarter of 2000. As discussed below in "Results of Operations," cash flow
from significant production from two new wells is expected to increase DCF
during the third and fourth quarters of fiscal 2000 and might exceed record
levels set in 1997. DCF is calculated without debt retirement being considered
but in Columbus' case this does not matter as current bank debt requires no
principal payments before August 1, 2001. Interest expense is always deducted
before arriving at DCF.
16
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.
Neither DCF nor operating cash flow before working capital changes is
allowed to be substituted for net income or for cash available from operations
as defined by GAAP. Furthermore, currently reported cash flows, however defined,
are not necessarily indicative that there will be sufficient funds for all
future cash requirements. For the first six months of 2000 and 1999 GAAP cash
flow was lower than DCF.
As previously indicated, the Company partially hedged its crude oil
prices while the Company's natural gas revenues are fully exposed to price
fluctuations, both positive and negative. The non-hedged portion of its crude
oil revenues are similarly exposed to price fluctuations.
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.
The only hedge in existence as of May 31, 2000 was a twelve month
costless "collar" for 7,500 barrels per month which expires August 31, 2000.
This hedge is more fully described in Note 5, "Commitments and Contingent
Liabilities", in the Notes to the Consolidated Financial statements.
As described in Note 2 "Long-Term Debt" at May 31, 2000, Columbus had
outstanding bank borrowings of $5,200,000 against its $10,000,000 line of credit
with Norwest Bank Denver, 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 0.18. The outstanding debt used a LIBOR
option with an average interest rate of 8.2%. Subsequent to the end of the
second quarter and through July 14, 2000, long-term debt will be reduced by a
total of $300,000 to $4,900,000. The net increase (or decrease) in long-term
debt directly affects cash flows from financing activities as do the purchase of
17
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.
Working capital at May 31, 2000 was a positive $1,343,000, up from
$1,169,000 at November 30, 1999, despite $684,000 spent for additions to oil and
gas properties, a significant amount of exploration expenditures, and a purchase
of 63,000 treasury shares for $357,000 during the first half of fiscal 2000.
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 May 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.
During first six months of 2000, capital expenditures actually
incurred for oil and gas properties totaled $684,000 (which amount excludes $1.7
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 first six months period were not
actually paid until subsequent to the end of the period.
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
RESULTS OF OPERATIONS
Gross revenues increased by 40% over last year's second quarter and
operating income increased to $823,000 in the current quarter compared to a loss
of $286,000 last year. Other comparisons for the 2000 quarter and six month
periods versus 1999 related to prices, production and oil and gas sales appear
in tabular form below.
During 2000's second quarter four gross wells (1.60 net WI) were
drilled. These included two (.66 net WI) gas development wells in Webb County,
Texas, and one (.04 net WI) dry hole located in the same area. One (.90 net WI)
exploratory oil recompletion attempt in a new zone in an existing well in
Montana was abandoned during the quarter.
The most significant development was a new gas well, the Hachar #36,
in which Columbus owns a 200% cost recovery 53.7% net revenue interest. This was
the result of numerous non-consent interests so this net revenue interest
reduces to 3.8% after that 200% recovery. This outstanding well commenced
production on May 10, 2000 and is producing in excess of 5,000,000 cubic feet of
natural gas and 100 barrels of condensate per day. Although the revenue and
production from the Hachar #36 benefited Columbus for less than one month during
second quarter, it will have a very large impact during the third quarter.
Payout of 200% of costs is expected to come from about four months of
production, or less, depending on price.
Subsequent to the end of the quarter during June, Columbus
successfully recompleted an additional exploratory well in a "behind-the-pipe"
Duperow zone in the Lien #2 located in Richland County, Montana. This added zone
initially raised production to in excess of 100 barrels of crude oil per day but
since has declined to approximately 75 barrels per day in early July. Columbus
owns 100% WI in this well.
19
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:
Second Quarter Six Months
--------------------------------- -------------------------------
2000 1999 Change 2000 1999 Change
------ ------ ------ ---- ---- ------
Natural gas revenues M$ $2,356 $1,678 40 % $ 4,131 $ 3,318 25 %
Oil revenue M$ $ 975 $ 593 64 % $ 1,940 $ 986 97 %
Natural gas sales volumes:
Millions of cubic feet (MMCF) 723 810 (11)% 1,429 1,686 (15)%
MCF/day 7,853 8,803 7,809 9,266
Oil sales volumes:
Barrels 40,600 39,402 3 % 81,863 77,347 6 %
Barrels/day 441 428 447 425
Average price received:
Natural gas - $/MCF $ 3.26 $ 2.07 57 % $ 2.89 $ 1.97 47 %
Oil - $/BBL $23.99 $15.05 59 % $23.69 $ 12.75 86 %
Natural gas revenues for the quarter increased by 40% over 1999's
second quarter due to 57% higher prices which were partially offset by 11% lower
sales volumes. Similarly, the six month period for 2000 had 25% higher natural
gas revenues due to 47% higher prices offset by 15% lower sales volumes. Average
gas prices improved steadily from depressed price levels during the early part
of 1999 that were a result of a very warm winter and relatively high storage
inventory replaced by summer's strong demand for cooling load and storage
refill. Supply shortfalls due to little or no excess gas capacity have caused
prices to exceed $4.00 per Mcf subsequent to quarter's end. Comparable periods
showed lower sales volumes in 2000 versus 1999 as a result of normal production
declines in older wells which were not offset by a development well program in
late 1999 and early 2000. However, second quarter successes in Webb County
already placed on production and a potentially successful Upper Wilcox
completion at the Long #5 has improved the outlook for a material increase in
gas production in fiscal 2000's last half.
Oil revenues for 2000's second quarter rose by 64% over the 1999 quarter because
average prices rose by 59% and sales volumes were 3% higher. Comparative six
month's results show 97% greater oil revenues because average prices were up 86%
and sales volumes up 6%. Oil revenues and average prices for 2000 were reduced
due to the crude oil hedge. Oil production had previously declined steadily for
the past few years commensurate with a lack of development drilling activity due
to low crude oil prices and lack of certainty of 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. There was one
exploratory gas well that found oil in Harris County, Texas, which was drilled
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
during fiscal 1998. This was connected to a gas line and commenced flowing 200
barrels of oil per day with associated gas during June 1999. Columbus' 19.5%
working interest in that well helped provide the slight improvement in crude oil
production reported for last half of 1999 and first half of 2000 versus earlier
periods. Prices for crude oil have continued to move upwards due to strong
demand and a restrictive production program instigated by OPEC. This program was
recently loosened by that group with their announced objective being a "basket"
of oil prices to average about $25 per barrel.
Columbus' second quarter sales volumes of natural gas averaged 7,853
Mcfd while oil and liquids sales volumes were 447 barrels per day which equates
to a daily sales volume of 10,536 MCF equivalent (Mcfe). This compares with
1999's second quarter rate of 11,407 Mcfe, an 8% decrease. As stated before,
this reduction was attributable to the lack of new development wells being
drilled along with a lack of exploratory success at Columbus' El Squared
prospect. Production from the previously mentioned Hachar #36 and Lien #2 wells
has already reversed this decline thus far in Columbus' third quarter. For
comparative six month's periods, average daily sales volumes were 10,532 Mcfe in
2000 versus 11,849 Mcfe in 1999 which were adversely affected by the
aforementioned reasons.
Lease operating expenses for the second quarter and first half of 2000
were 21% and 13% 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. However, several older
Williston Basin wells were shut-in during 1999's first half which accounts for
lower operating costs last year. Lease operating costs on an Mcfe basis were
$0.49 in the second quarter of 2000 compared to $0.40 in 1999 while operating
costs as a percentage of revenues were 14% in 2000 versus 19% in 1999 with its
lower prices but reduced costs. For comparative six month's periods, lease
operating costs were $0.53 per Mcfe in 2000 and $0.39 in 1999 but first half
lease operating costs as a percentage of revenues were 17% in 2000 and 20% in
1999.
Production and property taxes approximated 10% of revenues in 2000 and
12% 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.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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
---- ----
Second quarter $120,000 $114,000
Six Months $259,000 $199,000
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. During first quarter 1999,
sizable compressor repairs reduced profits for that period.
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 second quarter of 2000 to $36,000 from $19,000
in 1999's second 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.
The Company's general and administrative expenses were as follows:
2000 1999
---- ----
Second quarter $549,000 $440,000
Six months $877,000 $776,000
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Second quarter expenses exceeded last year's due to cash bonuses of
$178,000 in May with no stock option grants compared to 1999 incentive bonuses
of $80,000 ($58,000 non-cash) plus grants of stock options to all officers.
Also, there was a previously disclosed 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 being 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. Medical claims
under the Company's self- insured plan were higher for 2000's second quarter and
first half. Office rent was slightly lower during second quarter in 2000
compared to 1999 as a result of a sublease of a portion of the leased space but
for the six months period, rent expense and office parking was higher due to an
increase in the monthly rent. Both the second quarter and six month periods'
outside contract and professional services were reduced in fiscal 2000 versus
1999.
Unusual expenses were incurred during second quarter which relate to
exploring various strategic alternatives for the Company by use of financial
advisors. These totaled $119,000 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 decreased from 1999's second quarter
commensurate with decreased production even though there were some additional
development expenditures incurred in the intervening period. Reduced proved
reserves last year which resulted from lower crude oil prices were responsible
for a higher depletion rate in 1999's second quarter for some properties, but
since production was curtailed in several wells, the rise in overall depletion
expense for 1999 lessened. Despite the depreciation expense being lower in
2000's first quarter, the depletion rate of $.76 per Mcfe was identical to
1999's like period rate. The depletion rate for second quarter 2000 was $.73 per
Mcfe compared to $.77 per Mcfe for that like period of 1999. The decrease was
attributable to decreased production from fields having higher rates and
increased production from the Laredo area where there is a lower depletion rate.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Exploration Expense
In general, the exploration expense category includes the cost of
Company-wide efforts to acquire and explore new prospective areas. The
successful efforts method of accounting for oil and gas properties requires
expensing the costs of unsuccessful exploratory wells 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 $278,000 for 2000's second quarter were up from
1999's $225,000 and included $196,000 recompletion and abandonment costs for a
90%-owned exploratory well in Montana. A total of $160,000 was expensed for
participation in two shallow exploratory dry holes last year.
First half of fiscal 2000 exploration charges of $1,690,000 were up
significantly over 1999's. Most of these charges were incurred during the first
quarter during the sidetrack and testing phase of the Long #4 ($805,000) and the
initiation of a sidetrack of the Long #3 ($476,000) over the expiration of the
primary term of the lease. The latter operation was halted when it was learned
that the Massive Sand in the Long #4 failed to yield commercial rates of gas
production. Also, an accrual of $60,000 for abandonments of those wells was
made. An additional $28,000 was expensed during the second quarter to plug the
two wells. During 1999's first quarter, $47,000 was expensed for undeveloped
leases as a result of an offset dry hole being drilled.
Whenever a company using 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 costs.
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Impairments
No impairment loss was required for fiscal 2000's first half as the
higher prices of both natural gas and crude oil also contributed to an increase
in the fair market value of reserves above remaining book value of each cost
pool.
Last year at the end of the second quarter, there was a pre- tax,
non-cash impairment loss of $503,000 recorded. The improvement in crude oil
prices up to that time was insufficient to justify restoration of proved
undeveloped reserves in one of the Williston Basin's cost pools because the
return on new investments would be unsatisfactory. Therefore, restoration of
undeveloped reserves was deferred and the shortfall of $253,000 between
remaining book value of the pool and the 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 producing zones and natural gas reserves thereby
generating a pre- tax, non-cash impairment of $250,000.
Litigation Expense
The litigation expense relates to the Maris E. Penn, et al lawsuit
described in Note 4 of the Notes to the Financial Statements. Second quarter of
2000 also includes a small amount of legal expenses related to the recently
filed Fred E. Long, et al lawsuit.
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 this latest quarter was 7.6% which compares to
6.4% in 1999. For the six month periods average interest rates were 7.6% in 2000
and 6.6% in 1999.
Income Taxes
During the first half of 2000, the net deferred tax asset decreased
slightly to $1,135,000. The asset is comprised of a $110,000 current portion and
$1,025,000 long-term asset. The estimated decrease in deferred tax assets was
only $2,000 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.
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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
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 the Maris E. Penn, et al lawsuit jury trial
and verdict in favor of Columbus and a new 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 ABUT 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Annual meeting held May 4, 2000 in Denver, Colorado for the purpose of
electing members of the board of directors. Proxies for the meeting were
solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934 and
there was no solicitation in opposition to management's solicitations.
All of management's nominees for three Class II directors as listed in
the proxy statement were elected with the following vote:
Shares Shares Abstaining
Nominee Shares For Against or Withheld
------- ---------- ------- -----------
Harry A. Trueblood, Jr. 3,387,604 2,628 37,060
William H. Blount 3,388,654 1,578 37,060
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27 - Financial data schedule - May 31, 2000.
(b) Reports on Form 8-K
Report filed on May 31, 2000 related to
Management's Report to Shareholders for the First
Quarter Ended February 29, 2000 and the status of
a previously announced a program wherein the Board
of Directors hired financial advisors to aid them
in exploring strategic alternatives which would
maximize shareholder value.
27
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COLUMBUS ENERGY CORP.
(Registrant)
DATE: July 12, 2000 /s/ Harry A. Trueblood, Jr.
----------------------------- ---------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: July 12, 2000 /s/ Ronald H. Beck
----------------------------- ------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
28