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, 1999
---------------------------
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 October 8, 1999
- --------------------------- ------------------------------
Common stock, $.20 par value 3,818,558
COLUMBUS ENERGY CORP.
INDEX
PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
August 31, 1999 and
November 30, 1998 3
Consolidated Statements of Operations -
Three Months and Nine Months
Ended August 31, 1999 and 1998 5
Consolidated Statement of
Stockholders' Equity -
Nine Months Ended August 31, 1999 6
Consolidated Statements of Cash Flows -
Nine Months Ended August 31, 1999
and 1998 7
Notes to the 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 25
Items 2-5. Not Applicable
Item 6. Exhibits and Reports
on Form 8-K 25
Signatures 26
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
August 31, November 30,
1999 1998
------------ ------------
(unaudited)
(in thousands)
Current assets:
Cash and cash equivalents $ 1,403 $ 2,003
Accounts receivable:
Joint interest partners 1,228 1,570
Oil and gas sales 1,462 1,239
Allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 3) 36 327
Inventory of oil field equipment,
at lower of average cost or market 102 95
Other 158 106
------- -------
Total current assets 4,273 5,224
------- -------
Deferred income taxes (Note 3) 267 -
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 37,766 36,039
Other property and equipment 1,803 1,804
------- -------
39,569 37,843
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (21,678) (19,118)
------- -------
Net property and equipment 17,891 18,725
------- -------
$ 22,431 $ 23,949
======== ========
(continued)
3
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
August 31, November 30,
1999 1998
------------ ------------
(unaudited)
(in thousands)
Current liabilities:
Accounts payable $ 1,427 $ 1,846
Undistributed oil and gas
production receipts 292 317
Accrued production and property taxes 322 677
Prepayments from joint interest owners 359 374
Accrued expenses 363 415
Income taxes payable (Note 3) 28 2
Other 15 37
------ ------
Total current liabilities 2,806 3,668
------ ------
Long-term bank debt (Note 2) 5,600 4,900
Deferred income taxes (Note 3) - 117
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
4,645,303 in 1999, and 4,611,001 in 1998
(outstanding 3,864,558 in 1999 and
4,046,552 in 1998) 929 922
Additional paid-in capital 19,759 19,656
Retained earnings (accumulated deficit) (1,483) (1,440)
------ ------
19,205 19,138
Less: Treasury stock at cost
780,745 shares in 1999 and
564,449 shares in 1998 (5,180) (3,874)
------ ------
Total stockholders' equity 14,025 15,264
------ ------
$ 22,431 $ 23,949
====== ======
The accompanying notes are an integral part of these consolidated financial
statements.
4
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Nine Months Ended Three Months Ended
August 31, August 31,
-------------------------- ----------------------------
1999 1998 1999 1998
------- ------- ------- -------
(in thousands, except per share data)
Revenues:
Oil and gas sales $ 7,064 $ 8,113 $ 2,760 $ 2,495
Operating and management
services 1,025 988 353 362
Interest and other income 70 109 23 32
------- -------- -------- --------
Total revenues 8,159 9,210 3,136 2,889
------- -------- -------- --------
Costs and expenses:
Lease operating expenses 1,357 1,662 514 445
Property and production taxes 741 802 242 261
Operating and management
services 693 807 220 311
General and administrative 1,075 1,155 299 257
Depreciation, depletion and
amortization 2,571 2,834 847 944
Impairments 503 2,816 - -
Exploration expense 971 477 627 49
Litigation expense (Note 4) 41 - 24 -
-------- -------- -------- --------
Total costs and expenses 7,952 10,553 2,773 2,267
-------- -------- -------- --------
Operating income (loss) 207 (1,343) 363 622
-------- -------- -------- --------
Other expenses (income):
Interest 273 179 98 65
Other 4 30 1 (4)
------- ------- -------- --------
277 209 99 61
------- ------- -------- --------
Earnings (loss) before
income taxes (70) (1,552) 264 561
Provision (benefit) for income
taxes (Note 3) (27) (590) 100 213
------- -------- ------- --------
Net earnings (loss) $ (43) $ (962) $ 164 $ 348
======= ======== ======= ========
Earnings (loss) per share (Note 7):
Basic $ (.01) $ (.23) $ .04 $ .08
======= ======== ======== ========
Diluted $ (.01) $ (.23) $ .04 $ .08
======= ======== ======== ========
Average number of common shares
and common equivalent shares outstanding:
Basic 3,920 4,232 3,870 4,209
======= ======== ======= ========
Diluted 3,920 4,232 3,873 4,266
======= ======== ======= ========
The accompanying notes are an integral part of these consolidated financial
statements.
5
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Nine Months Ended August 31, 1999
(Unaudited)
Retained
Common Stock Additional Earnings Treasury Stock
-------------------- Paid-in (Accumulated ---------------------
Shares Amount Capital deficit) Shares Amount
--------- --------- ----------- ------------ -------- ---------
(dollar amounts in thousands)
Balances,
December 1, 1998 4,611,001 $ 922 $ 19,656 $ (1,440) 564,449 $ (3,874)
Exercise of employee
stock options 23,320 5 63 -- 855 24
Purchase of shares -- -- -- -- 236,540 (1,471)
Shares issued for Stock
Purchase Plan 10,982 2 66 -- (2,759) 19
Shares issued for
Incentive Bonus Plan
and directors' fees -- -- (38) -- (18,340) 122
Tax benefit of stock
option exercises -- -- 12 -- -- --
Net loss -- -- -- (43) -- --
--------- --------- --------- --------- --------- ---------
Balances,
August 31, 1999 4,645,303 $ 929 $ 19,759 $ (1,483) 780,745 $ (5,180)
========= ========= ========= ========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
6
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended August 31,
--------------------------------------
1999 1998
------- --------
(in thousands)
Net earnings (loss) $ (43) $ (962)
Adjustments to reconcile net earnings
(loss) to net cash provided by
operating activities:
Depreciation, depletion, and
amortization 2,571 2,834
Impairments 503 2,816
Deferred income tax provision (benefit) (81) (653)
Exploration expense, noncash portion 80 -
Other 108 249
Net change in operating assets and
liabilities (630) 1,776
-------- -------
Net cash provided by
operating activities 2,508 6,060
-------- -------
Cash flows from investing activities:
Additions to oil and gas properties (2,487) (6,149)
Additions to other assets (11) (101)
-------- -------
Net cash used in
investing activities (2,498) (6,250)
-------- -------
Cash flows from financing activities:
Proceeds from long-term debt 1,100 1,800
Reduction in long-term debt (400) (700)
Proceeds from issuance of
common stock 161 457
Purchase of treasury stock (1,471) (1,831)
Other - (2)
------ -------
Net cash provided by (used in)
financing activities (610) (276)
------ -------
Net decrease in cash and
cash equivalents (600) (466)
Cash and cash equivalents at
beginning of period 2,003 1,857
------ -------
Cash and cash equivalents at
end of period $ 1,403 $ 1,391
====== =======
(continued)
7
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS - (continued)
(Unaudited)
Nine Months Ended August 31,
--------------------------------------
1999 1998
------- --------
(in thousands)
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 271 $ 177
====== =======
Income taxes, net of refunds $ 28 $ 46
====== =======
Supplemental disclosure of non-cash investing and financing activities:
Non-cash compensation expense
related to common stock $ 103 $ 171
====== =======
The accompanying notes are an integral part of these consolidated financial
statements.
8
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
(Unaudited)
(1) BASIS OF PRESENTATION
The accompanying consolidated financial statements include the
accounts of Columbus Energy Corp. ("Columbus") and its wholly-owned
subsidiaries, 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, 1999 and November 30, 1998, 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, 1998. 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. In June 1999, the
Statement of Financial Accounting Standards No. 137 deferred the effective date
for the Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities," to fiscal years beginning after
June 15, 2000. The Company must apply this standard no later than December 1,
2000. These quarterly financial statements should be read in conjunction with
the consolidated financial statements and notes included in the 1998 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%.
9
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
The borrowing base is limited to $10,000,000 and subject to semi-annual
redetermination for any increase or decrease. At August 31, 1999 outstanding
borrowings on the revolving line of credit were $5,600,000 and the unused
borrowing base available was $4,400,000. 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.
(3) INCOME TAXES
The provision (benefit) for income taxes consists of the following (in
thousands):
Nine Months Ended August 31,
-----------------------------
1999 1998
-------- --------
Current:
Federal $ 25 $ 6
State 29 57
----- -----
54 63
----- -----
Deferred:
Federal (84) (632)
Use of loss carryforwards 6 5
State (3) (26)
----- -----
(81) (653)
----- -----
Total income tax (benefit) expense $ (27) $ (590)
====== ======
10
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
During the nine months of fiscal 1999, certain tax assets (shown in
the table below) were utilized. The tax effect of significant temporary
differences representing deferred tax assets and liabilities and changes were
estimated as follows (in thousands):
Current Year
--------------------------------------------------
Stock-
Dec. 1, holders' Operations/ August 31,
1998 Equity Other 1999
-------- --------- ---------- ----------
Deferred tax assets:
Pre-1987 loss carryforwards $1,124 $ - $ - $1,124
Post-1987 loss carryforwards 540 - 2 542
Percentage depletion
carryforwards 1,478 - - 1,478
State income tax loss
carryforwards 118 - (6) 112
Other 329 - (17) 312
------- ------ ------ ------
Total 3,589 - (21) 3,568
Valuation allowance
(long-term) (1,408) - - (1,408)
-------- ------ ------ ------
Deferred tax assets 2,181 - (21) 2,160
-------- ------ ------ ------
Tax benefit of stock option
exercises - 12(a) (12) -
-------- ------ ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (1,971) - 114 (1,857)
-------- ------ ------ ------
Net tax asset (liability) $ 210 $ 12 $ 81 $ 303
======== ====== ======= =======
(a)Credited to additional paid-in capital.
(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 District Court of
Harris County, Texas. The plaintiffs claim that Columbus breached the settlement
agreement of their previous lawsuit reached in September 1994 by failing to
develop properties located within the area of mutual interests and to act as a
reasonably prudent operator in the development of the property. Plaintiffs
allege damages under the contract but no amount is specified. Columbus denied
claims and has responded with a First Set of Interrogatories, First Request for
Production of Documents and Request for Disclosure to Plaintiffs. Columbus filed
Special Exceptions to Plaintiffs' Original Petition which were sustained by the
Judge who concurred that those portions of the complaint were not in accordance
with Texas law. The Plaintiffs were given a limited time frame in which to amend
11
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
their petition with respect to those key paragraphs for which Columbus'
exceptions were sustained or the case would be dismissed. Plaintiffs did refile
their petition but included those same paragraphs and added a section entitled
"Breach of Implied Covenant to Develop the Area of Mutual Interest" as an
alternative to their original Pleadings. Columbus subsequently filed its Motion
for Summary Judgment which the Court did not grant. Trial date has been set for
January 24, 2000. Management believes the Plaintiffs' claims are without merit
and an implausible construction of what was agreed upon in settlement of the
previous lawsuit.
(5) COMMITMENTS AND CONTINGENT LIABILITIES
When the Company uses natural gas and crude oil swaps they are
considered financial instruments with off-balance sheet risk which are 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 do
involve, to varying degrees, elements of market and credit risk in excess of the
amount recognized in the balance sheets.
The Company had no natural gas swaps outstanding as of August 31,
1999. Columbus has hedged approximately 50% of its current crude oil production
with a costless "collar" on 7,500 barrels per month for the 12 months from
September 1, 1999 through August 31, 2000. The price 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. For any price below or above those prices
Columbus receives or pays the difference. The month of September was settled for
$11,543 paid by Columbus. For the remaining period of October 1999 through
August 2000 for prices as of October 11, 1999 there was no settlement value to
either party.
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 thereto. There is no way management can predict
what future environmental control problems may arise. The continually changing
character of environmental regulations and requirements that might be enacted in
future by jurisdictional authorities in various operational areas defies
forecasting.
(6) RELATED PARTY TRANSACTIONS
CEC Resources Ltd. ("Resources") was a wholly-owned subsidiary of
Columbus prior to its divestiture on February 24, 1995. Reimbursement has been
made by Resources to Columbus for services provided by Columbus officers and
12
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
employees for managing Resources in the past which reduced general and
administrative expense. This reimbursement totaled $33,000 and $185,000 for the
nine months of 1999 and 1998, respectively. Effective on March 31, 1999, the
agreement to continue furnishing those services was terminated by Columbus
following the 90 day prior notice period as provided.
(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,
1999 1998 1999 1998
---- ---- ---- ----
(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) $ (43) $ (962) $ 164 $ 348
====== ===== ===== =====
Shares (denominator):
Basic EPS 3,920 4,232 3,870 4,209
Effect of dilutive option
shares - - 3 57
------ ----- ----- -----
Diluted EPS 3,920 4,232 3,873 4,266
====== ===== ===== =====
Per share amount:
Basic EPS $ (.01) $ (.23) $ .04 $ .08
====== ===== ===== =====
Diluted EPS $ (.01) $ (.23) $ .04 $ .08
====== ===== ===== =====
Number of shares (in thousands)
not included in basic EPS that
would have been antidilutive
because exercise price of options
was greater than the average
market price of the common shares 612 170 626 170
====== ===== ===== =====
Historical average number of shares outstanding and earnings per share
have been adjusted for the 10% stock dividend distributed March 9, 1998 to
shareholders of record as of February 23, 1998.
13
COLUMBUS ENERGY CORP.
NOTES TO THE 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:
Nine Months Three Months
Ended August 31, Ended August 31,
---------------------- ---------------------
1999 1998 1999 1998
---- ---- ---- ----
(in thousands)
Operating revenues from unaffiliated services:
Oil and gas $ 7,071 $ 8,124 $ 2,762 $ 2,500
Services 1,088 1,086 374 389
------- ------- ------- -------
Total $ 8,159 $ 9,210 $ 3,136 $ 2,889
======= ======= ======= =======
Depreciation, depletion
and amortization:
Oil and gas $ 2,528 $ 2,792 $ 833 $ 930
Services 43 42 14 14
------- ------- ------- -------
Total $ 2,571 $ 2,834 $ 847 $ 944
======= ======= ======= =======
Operating income (loss):
Oil and gas $ 930 $ (425) $ 523 $ 815
Services 351 237 138 64
General corporate
expenses (1,074) (1,155) (298) (257)
------- ------- ------- -------
Total operating income 207 (1,343) 363 622
Interest expense and other (277) (209) (99) (61)
------- ------- ------- -------
Earnings (loss) before
income taxes $ (70) $(1,552) $ 264 $ 561
======= ======= ======= =======
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
Third quarter 1999 oil and gas sales continued to improve over recent
prior periods when dismal crude oil prices prevailed along with weak natural gas
prices although production of each product was higher. The current quarter's
cash flow increased 12% above last year's similar period and was the highest
quarter since fourth quarter in fiscal 1997. Net earnings for third quarter 1999
were $164,000, or $0.04 per share because of higher revenues but were reduced by
exploration expense of $627,000 ($389,000 net of income tax effect) as explained
below. This compares with 1998's third quarter net earnings of $348,000, or
$0.08 per share.
Stockholders' equity as of the end of 1999's third quarter decreased
to $14,025,000 from $15,264,000 at November 30, 1998 while working capital was
down to $1,467,000 from $1,556,000. Contributing factors were purchases of
treasury shares and cash expended for additions to properties which approximated
the cash provided by operating activities. There was a net $700,000 increase in
long term bank debt since fiscal year end.
Management expects that cash flow for the whole year will provide more
than sufficient funds for fiscal 1999's originally planned capital expenditure
program of approximately $4,000,000 which has concentrated on developing proved
undeveloped natural gas reserves. An onshore exploratory drilling program in the
lower Texas Gulf Coast area on EGY's existing El Squared prospect leaseholds has
been the principal expenditure. The unused portion of the $10,000,000 bank
credit facility has primarily in the past been earmarked for acquisitions of oil
and gas properties, but could be used for any corporate purpose. This unused
portion of the bank line is available if unforeseen additional capital
expenditure requirements arise during the remainder of 1999 because of
accelerated drilling activities.
Net cash provided by operating activities was $3,039,000 for the nine
months of 1999, which compares with $6,060,000 for the same period last year.
This cash flow, coupled with added $700,000 use of the Company's credit
facility, has provided liquidity to fund both capital expenditures and treasury
share repurchases through August 31, 1999.
15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
As regularly reported in the past, 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
generally accepted accounting principles ("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 where exploration expenses are capitalized and
do not immediately adversely affect either operating cash flow or net earnings.
Columbus' DCF for the nine months of 1999 was $4,029,000 down 15% from 1998's
similar period which was $4,761,000. Third quarter DCF of $1,749,000 in 1999
surpassed by 12% 1998's $1,561,000 and if DCF for the month of August becomes
the average for each month during the fourth quarter, then fiscal 1999's DCF
will surpass that of fiscal 1998. This will be accomplished despite 1999's first
quarter DCF being the lowest for any quarter since fiscal 1995. As previously
indicated, this third quarter increase was primarily attributable to higher
natural gas and crude oil prices because daily production stated in Mcf
equivalent was down 14% from last year's similar period. DCF is calculated
without any 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 dedu cted before arriving at DCF.
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 nine months of 1999, GAAP cash flow was lower
than DCF but just the opposite has been true on several occasions in prior
periods.
16
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
The Company had no natural gas price hedges in place as of August 31,
1999 however it has hedged approximately 50% of its current crude oil production
with a costless "collar" on 7,500 barrels per month for the 12 months beginning
on September 1, 1999 through August 31, 2000. The price 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. For any price below or above those prices
Columbus receives or pays the difference. Therefore, the Company's oil revenues
will no longer be fully exposed to the risk of declining prices such as occurred
during most of fiscal 1998 and first four months of fiscal 1999. However, the
Company was able to realize the full benefit of all price increases that
appeared late in the second quarter 1999 and throughout the third quarter since
it was not limited on a portion of its oil production to the upside by the
$22.25 price which began as of September 1st.
Columbus had outstanding bank borrowings of $5,600,000 as of August
31, 1999 against its $10,000,000 line of credit with Norwest Bank Denver, N.A.
which is collateralized by oil and gas properties. On that same date the ratio
of net long-term debt (debt less working capital) to shareholders' equity was
0.29 and to total assets was 0.18. Outstanding long term debt utilized a LIBOR
option with an average interest rate of 6.8%. Subsequent to the end of the third
quarter, Columbus has reduced bank debt by $100,000. The net increase (or
decrease) of long-term debt directly affects cash flows from financing
activities as do the purchase of treasury shares or the proceeds from the
exercise of stock options.
Working capital at August 31, 1999 declined to $1,467,000 from
$1,556,000 at November 30, 1998 for reasons discussed earlier. Actual nine
months capital expenditures related to 1999 were $2,309,000 for additions to oil
and gas properties and $1,471,000 for the purchase of 236,540 treasury shares
($6.20/share) both of which did affect working capital. However, the
aforementioned 1999 actual capital expenditures differ from the amount shown in
the consolidated Statement of Cash Flows because the latter capital expenditures
include costs which had been incurred during 1999 but had not yet been paid by
the end of the third quarter which amount was less than the unpaid expenditures
accrued at the beginning of the year.
Management has for several years been authorized from time to time by
the Board of Directors to repurchase its common shares from the market in blocks
subject to price limitations. In February, May and July 1999, authorizations
were approved to purchase 100,000, 50,000 and 50,000 shares, respectively, with
the latter two restricted to purchase prices not to exceed $6.00 per share were
17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
added to previous authorizations. The 100,000 share and a portion of the first
50,000 share authorization had been utilized by the end of the third quarter.
Subsequently, in September and thus far during October 1999, 46,000 additional
shares have been acquired at an average price of $5.66 per share. This leaves
approximately 41,000 shares of the July 1999 authorization yet to be purchased
at prices of $6.00 or less. Total treasury shares on hand as of October 11, 1999
amounted to 826,745 shares.
RESULTS OF OPERATIONS
During 1999's third quarter, gross revenues increased by 11% and
operating income increased to $894,000 from $622,000 in 1998. Higher product
prices were responsible for these increases since lower oil and gas volumes were
realized. Other comparisons for the 1999 quarter and nine month periods versus
1998 related to prices, production and oil and gas sales appear in tabular form
below.
During 1999's third quarter five gross wells (2.23 net WI) were
drilled. These included three (.89 net WI) gas development wells in Webb County,
Texas, and two (1.34 net WI) recompletions in new zones of existing oil wells in
Montana. In progress wells at quarter's end included one wildcat well, Long #3,
which was being directionally deepened to the middle Wilcox Massive Sand and is
located in the El Squared prospect in Bee County, Texas and one development gas
well in the Laredo, Texas operational area.
Oil and Gas Revenues and Operating Costs
The following table shows comparative crude oil and natural gas
revenues, sales volumes, average prices and percentage changes between the
periods presented as follows:
Third Quarter Nine Months
--------------------------------- -------------------------------
1999 1998 Change 1999 1998 Change
------ ------ ------ ---- ---- ------
Natural gas revenues M$ $1,943 $1,914 2 % $ 5,261 $ 5,847 (10)%
Oil revenue M$ $ 817 $ 581 41 % $ 1,803 $ 2,266 (20)%
Natural gas sales volumes:
Millions of cubic feet (MMCF) 765 892 (14)% 2,451 2,609 (6)%
MCF/day 8,310 9,696 8,945 9,523
Oil sales volumes:
Barrels 44,434 50,944 (13)% 121,781 168,183 (28)%
Barrels/day 483 554 444 614
Average price received:
Natural gas - $/MCF $ 2.54 $ 2.15 18 % $ 2.15 $ 2.24 (4)%
Oil - $/BBL $18.38 $11.41 61 % $14.80 $13.48 10 %
18
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Natural gas revenues increased 2% in the third quarter of 1999 versus
1998 because 18% higher prices were significantly offset by lower sales volumes.
Average gas prices have recovered from depressed prices which resulted from a
warm winter and a high level inventory of storage gas. Comparable quarters
showed 14% lower sales volumes in 1999 due to production declines not fully
offset by Slick Sand gas currently being produced at the El Squared prospect's
Long #1 and Long #2 wells or by recently drilled gas wells in the Laredo, Texas
area. For the 1999 nine month period, natural gas revenues declined 10% from
1998 which was the result of a 6% decrease in average sales volumes and a 4%
decrease in average prices.
Oil revenues for 1999's third quarter were higher by 41% than the 1998
quarter because prices rose by 61% but sales volumes were 13% lower. Oil
production has declined steadily with no development drilling activity because
of depressed oil prices for the past two years. However, an exploratory oil well
in Harris County, Texas, drilled during 1998, was finally hooked-up and
commenced producing 200 barrels per day in mid-June 1999. Columbus owns a 19.5%
working interest. Crude oil prices began a move upwards late in the second
quarter and accelerated during the third quarter. Similar reasons for the
quarter apply to comparative nine month's results because both oil revenues and
volumes were lower by 20% and 28%, respectively, while crude oil prices were
only 10% higher.
Columbus' 1999 third quarter sales volumes of natural gas averaged
8,310 Mcfd while oil and liquids production were 489 barrels per day. These
equate to an average daily sales volumes of 11,245 MCF equivalent (Mcfe)
compared to 1998's third quarter rate of 13,073 Mcfe, a 14% decrease. This was
attributable to declines of both gas and oil production which have not been
totally replaced with production from newly completed wells. For the nine
month's periods, average daily sales volumes were 11,646 Mcfe in 1999 versus
13,254 Mcfe in 1998 which were affected downward in 1999 and upward in 1998 by
retroactive reversion adjustments in the first quarters of each of those years
in addition to those same reasons outlined for the third quarter.
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Lease operating expenses for the third quarter of 1999 were 16% higher
than in 1998. A good portion of the increase was in the Sralla Road field in
Texas where one well had significant workover costs. Also, there was a general
increase in operating costs following the start up of old wells and a few
repairs and replacements to equipment. Lease operating expenses for the nine
months in 1999 were 18% lower than 1998's comparable period. Expensive workovers
and replacements of downhole and surface equipment on older wells had occurred
during that period in 1998 while several of those older wells were shut-in
earlier in 1999. Lease operating costs on a Mcfe basis were $0.50 in the third
quarter of 1999 compared to $0.37 in 1998 while operating costs as a percentage
of revenues were 19% in 1999 versus 18% in 1998 with its lower prices but higher
production. For the nine months periods lease operating costs were $0.43 per
Mcfe in 1999 and $0.46 in 1998 and lease operating costs as a percentage of
revenues were 19% in 1999 and 20% in 1998.
Production and property taxes approximated 10% of revenues in both
1999 and 1998 nine month periods. These vary based on Texas' percentage share of
the total production where oil tax rates are lower than gas tax rates. The
relationship of taxes and revenue is not always directly proportional since 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 opera tions 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:
1999 1998
---- ----
Third quarter $133,000 $ 51,000
Nine months $332,000 $181,000
In 1998, operations included unusually high workover expenses required to clean
out sand from the well bore of a salt water disposal well in Texas while 1999's
costs included sizable compressor repairs. Revenues improved during 1999 as the
number of operated wells increased supplemented by an increase from 50% to 100%
ownership interest in four compressors operating in South Texas.
20
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Interest Income
Interest income is earned primarily from short-term invest ments whose
rates fluctuate with changes in the commercial paper rates and the prime rate.
Interest income decreased in the third quarter of 1999 to $23,000 from $32,000
in 1998's third quarter primarily as a result of a lower amount of investments
and lower short-term interest rates.
General and Administrative Expenses
General and administrative expenses are considered to be those which
relate to the direct costs of the Company which do not originate from operation
of properties or providing of services. Corporate expense represents a major
part of this category.
The Company's general and administrative expenses were as follows:
1999 1998
---- ----
Third quarter $ 299,000 $ 257,000
Nine months $1,075,000 $1,155,000
Third quarter of 1999's expenses were more than last year due to the previously
disclosed total phase out of reimbursement for services provided for the
management of Resources which occurred during the second quarter of 1999 which
effectively increased costs by that prior credit. Reimbursement of $1,000 for
1999 from that source compares with $62,000 during 1998's third quarter while
nine month's comparisons were $33,000 for 1999 and $185,000 for 1998. During
third quarter salary expenses were comparable in 1999 and 1998. Salary increases
had been granted effective December 1, 1998 for non-officer employees while
officer salaries remained unchanged but incentive compensation and bonus costs
were reduced in 1999 which also affected the nine month's comparisons. Higher
medical claims under the Company's self-insured plan raised costs for 1999's
third quarter and nine months periods.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are
calculated based upon the units of production for the period compared to proved
reserves of each successful efforts property pool. This expense is not only
directly related to the level of production, but is also dependent upon past
costs to find, develop, and recover related reserves in each of the cost pools
or fields. Depreciation and amortization of office equipment and computer
software is also included in the total charge.
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Charges for this expense item decreased from 1998's third quarter as a
result of decreased production and despite additional development expenditures
in the intervening period. Reduction in proved reserves contributed to a small
increase in the depletion rate per Mcfe to $.78 per Mcfe for the nine months.
The 1999 third quarter depletion rate of $.79 per Mcfe compares with $.77 per
Mcfe for the like period of fiscal 1998 and $.77 per Mcfe for all of 1998.
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. Exploration charges of $627,000 for 1999's third
quarter were up from 1998's $49,000. Third quarter 1999 included $531,000 of
costs through August 31, 1999 to deepen the Long #3 exploratory well in the El
Squared prospect which did not find any proved reserves. Additional costs of
$150-200,000 incurred subsequent to quarter end may be expensed fourth quarter.
The remaining $382,000 costs to drill the well to a shallower zone are
classified as "in progress" pending a possible attempt to locate proved reserves
in a shallower formation. Also, seismic interpretation costs of $30,000 in the
El Squared prospect in Texas were expensed. In 1999's nine months a total of
$233,000 was expensed for participation in three exploratory dry holes. During
1998's quarter and nine month periods, expenses of $49,000 and $477,000 included
charges for 3-D seismic and an exploratory dry hole drilled in Montana.
Whenever a company which reports using the successful efforts method
of accounting is involved in an exploratory program that represents a
significant part of its budget, it subjects itself to the probable risk that net
earnings for a given quarter or a year will be severely impacted negatively by
such exploratory costs. With the numerous exploratory well bores involved at
Columbus' El Squared Prospect that will be required to properly evaluate the
various fault blocks and/or potential producing horizons, shareholders are
forewarned that net earnings and GAAP cash flow may not be truly indicative of
the success of the Company's operational activity. Management believes
shareholders should continue to place more emphasis on Discretionary Cash Flows
for the year as we do and not compare our results with other company's net
earnings or cash flows who use the full cost accounting method and capitalize
their exploratory costs.
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Impairments
At the end of 1999's second quarter, a pre-tax, non-cash impairment
loss of $503,000 was recorded. The improvement in crude oil prices previously
discussed was insufficient to justify restoration of proved undeveloped reserves
in one of the Williston Basin's cost pools because the return on investment
would be unsatisfactory. When crude oil prices in that area might reach and
maintain $20 per barrel could not be forecasted, so it was determined
restoration of undeveloped reserves would be deferred and the shortfall of
$253,000 between remaining book value of the pool and the current fair market
value of its reserves was recognized as a charge. Elsewhere, an unexpected
influx of water in natural gas wells in the shallow Heidi property in Jim Wells
County, Texas brought on premature abandonment of producing zones and associated
natural gas reserves which generated a pre-tax, non-cash impairment of $250,000.
A non-cash impairment loss of $2,816,000 in 1998's first quarter was
primarily generated by low crude oil prices and to a Louisiana exploratory
well's poor performance. Those low prices caused a write down in both developed
and undeveloped oil reserve quantities along with a reduction in the remaining
carrying value of several of the successful efforts pools when the unamortized
costs suddenly exceeded a newly calculated undiscounted future net cash flows.
Certain of these property pools were written down to an estimated fair value
using the assumption that the average future crude oil price would be $18.75 per
barrel over the remaining life of those pools. An additional $400,000 of
impairments were also provided for probable loss in value of undeveloped acreage
holdings (unproved properties) located primarily in Louisiana plus $56,000 was
expensed for an expired lease.
Interest Expense
Interest expense varies in direct proportion to the amount of bank debt and
the level of bank interest rates. The average amount of bank debt outstanding
has been higher during 1999's quarters than in 1998. The average bank interest
rate paid this latest quarter was 6.6% which compares to 7.1% in 1998. For the
nine month periods average interest rates were 6.6% in 1999 and 7.2% in 1998.
Income Taxes
During the nine months of 1999, the net deferred tax asset increased
to $303,000. The asset is comprised of a $36,000 current asset and a $267,000
long-term asset. A tax deduction of $12,000 from the benefit of stock option
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
exercises has been added to additional paid-in capital during 1999. The
estimated increase in deferred tax assets was $93,000 during the nine months.
The valuation allowance has remained unchanged thus far in 1999. The effective
tax rate for 1999 is 38%. See Note 3 to the con solidated financial statements
for further explanation of income taxes.
Impact of the Year 2000 issue. The Year 2000 issue is the result of
computer programs being written using two digits rather than four, or other
methods, to define the applicable year. Computer programs that have
date-sensitive software may recognize a date using "00" as the year 1900 rather
than the year 2000 and could result in a system failure or miscalculations
causing disruptions of operations such as a temporary inability to process
transactions, transmit invoices or engage in similar normal business activities.
The Company upgraded its major system computer software in 1997 to a
new release of a major software vendor that the vendor represents is compliant
with the year 2000. Columbus has reviewed its other less important systems as
well as its significant suppliers, purchasers, and transporters of oil and gas
to determine the extent to which the Company might still be vulnerable to other
failures and what the impact might be on its operations.
The Company's interest in wells operated by other companies is not
considered to be as important but management is attempting to determine if those
companies are ready for the year 2000. The Company uses outside services for
payroll and medical benefits processing and those companies have provided
updates to their software that they represent is year 2000 compliant. The
Company is also somewhat dependent upon personal computers as well as certain
spreadsheet and word processing software programs which may not be year 2000
compliant. Evaluations have been made to establish which of those systems are
critical and a few personal computers and software programs were replaced.
The Company also relies on non-information technology systems, such as
office telephones, facsimile machines, air conditioning, heating and elevators
in its leased office space, which may have embedded technology such as micro
controllers and are generally outside of its control to assess or remedy. These
might adversely impact the Company's business but in management's opinion would
not create a material disruption.
As previously disclosed, the major system computer software upgrade
performed in 1997 cost $16,000. This represents the majority of the costs,
including replacement of any non-compliant information technology system,
required to meet its goal of being year 2000 ready for mission-critical systems.
24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
The Company does not believe that any loss of revenue will occur as a result of
the year 2000 problem but regardless of efforts to identify and remedy such
problems, there could be year 2000 related failures that cause some disruption
to the Company's operations or temporary delays in processing certain data. The
Company has not established a contingency plan because we believe all major
issues have been resolved. Should year 2000 failures occur we will address them
at that time.
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.
PART II - OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Management is unaware of any asserted or unasserted claims or
assessments against the Company which would materially affect the Company's
future financial position or results of operations.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27 - Financial data schedule - August 31, 1999.
(b) Reports on Form 8-K
None.
25
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 18, 1999 /s/ Harry A. Trueblood, Jr.
---------------- -----------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 18, 1999 /s/ Ronald H. Beck
---------------- -----------------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
26