SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the Fiscal Year Ended Commission File Number
November 30, 1997 1-9872
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COLUMBUS ENERGY CORP.
(Exact name of Registrant as specified in its Charter)
COLORADO 84-0891713
(State of incorporation) (I.R.S. Employer Identification
No.)
1660 Lincoln Street 80264
Denver, Colorado (Zip code)
(Address of principal executive offices)
Registrant's telephone number, including area code:
(303) 861-5252
Securities registered pursuant to
Section 12(b) of the Act:
Name of each Exchange on
Title of each class which registered
------------------- ----------------
Common Stock, ($.20 par value) American Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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, and (2) has been subject to such filing
requirements for the past 90 days. Yes __X__ No _____.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of January 31, 1998 is $25,374,000.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of January 31, 1998
Outstanding at
Class January 31, 1998
----- ----------------
Common Stock, ($.20 par value) 3,863,907 shares
DOCUMENTS INCORPORATED BY REFERENCE
Columbus Energy Corp. definitive proxy statement to be filed no later than
120 days after the end of the fiscal year covered by this report, is
incorporated by reference into Part III.
<PAGE>
ANNUAL REPORT (S.E.C. FORM 10-K)
INDEX
Securities and Exchange Commission
Item Number and Description
PART I
Page
----
Item 1. Business...........................................................3
Item 2. Properties - Oil and Gas Operations .............................. 5
Item 3. Legal Proceedings.................................................22
Item 4. Submission of Matters to a
Vote of Security Holders.......................................22
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters................................23
Item 6. Selected Financial Data...........................................24
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................25
Item 8. Financial Statements and Supplementary Data.......................38
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.........................38
PART III
Item 10. Directors and Executive Officers
of the Registrant..............................................39
Item 11. Executive Compensation............................................39
Item 12. Security Ownership of Certain Beneficial
Owners and Management..........................................39
Item 13. Certain Relationships and
Related Transactions...........................................39
PART IV AND SIGNATURES
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K..............................40
Signatures........................................................72
2
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PART I
Item 1. BUSINESS
Columbus Energy Corp. ("Columbus") was incorporated under the laws of the
State of Colorado on October 7, 1982. Columbus engages in the production and
sale of crude oil, condensate and natural gas, as well as the acquisition and
development of leaseholds and other interests in oil and gas properties, and
also acts as manager and operator of oil and gas properties for itself and
others. It also engages in the business of compression, transmission and
marketing of natural gas through its wholly-owned subsidiary, Columbus Gas
Services, Inc. ("CGSI"), a Delaware corporation. Prior to February 1995 CEC
Resources Ltd. (Resources"), an Alberta, Canada corporation, was another
wholly-owned subsidiary. The term "Company" or "EGY" as used herein includes
Columbus and its subsidiaries.
The Company currently has 34 employees. The current technical staff,
including management, is comprised of four petroleum engineers and one landman.
The administrative staff provides support required for accounting and data
processing including disbursement of monthly oil and gas revenues, joint
interest billing functions, and accounts payable.
On February 24, 1995, Columbus completed a rights offering to the Columbus
shareholders to purchase one share of Resources for U.S.$3.25 cash plus two
subscription rights. One right was distributed as a dividend for each share held
of record on January 27, 1995. All 1,500,000 shares of Resources common stock
offered were subscribed (and oversubscribed) yielding an aggregate of
U.S.$4,875,000 in cash. The total value assigned to the rights for book purposes
was U.S.$582,000 which was the dividend portion of the total divestiture amount
for the Resources' shares. A deduction of $126,000 for the costs of the offering
was recorded. No gain or loss could be recognized for book purposes in a
spin-off and no taxes were due Revenue Canada as a result of this divestiture
because Columbus' Canadian tax basis in the Resources' shares exceeded the value
of the rights plus cash proceeds received from the offering.
During 1997, Columbus declared a five-for-four stock split for shareholders
of record as of May 27 which was distributed on June 16, 1997 and was issued
from authorized but unissued shares. Two prior 10% stock dividends in 1994 and
1995 were paid from treasury shares reacquired from the market and therefore
reduced cumulative retained earnings and increased paid-in capital. No cash
dividends have been paid since the Company became publicly-owned in 1988.
3
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From shortly after its incorporation until January 1988, the Company was a
wholly-owned or majority owned subsidiary of Consolidated Oil & Gas, Inc.
("Consolidated") after which time it became a separate publicly-owned entity as
a result of a spin-off via a rights offering by Consolidated to its
shareholders.
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Item 2. PROPERTIES
Oil and Gas Properties
Reserves
The estimated reserve amounts and future net revenues were determined by
outside consulting petroleum engineers. The reserve tables presented below show
total proved reserves and changes in proved reserves owned by Columbus for the
three years ended November 30, 1997, 1996 and 1995.
PROVED OIL AND GAS RESERVES
---------------------------
<TABLE>
<CAPTION>
Oil Natural Gas
(Thousands of Barrels) (Millions of Cubic Feet)
United United
Total States Canada Total States Canada
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
December 1, 1994 2,671 2,225 446 41,800 18,319 23,481
Revision to previous estimates (61) (113) 52 (2,698) (2,330) (368)
Purchase of reserves 117 117 - 397 397 -
Extensions, discoveries and other
additions 31 31 - 505 505 -
Production (236) (225) (11) (2,479) (2,033) (446)
Sale of reserves (divestiture) (487) - (487) (22,667) - (22,667)
------- ------- ------ --------- -------- --------
November 30, 1995 2,035 2,035 - 14,858 14,858 -
Revision to previous estimates (278) (278) - (1,335) (1,335) -
Purchase of reserves 17 17 - 4,808 4,808 -
Sale of reserves (35 (35) (170) (170) -
Extensions, discoveries and other
additions 150 150 - 3,190 3,190 -
Production (246) (246) - (2,686) (2,686) -
------- ------- ------ --------- -------- --------
November 30, 1996 1,643 1,643 - 18,665 18,665 -
Revision to previous estimates (127) (127) - 226 226 -
Sale of reserves - - - (2,067) (2,067) -
Extensions, discoveries and other
additions 538 538 - 5,066 5,066 -
Production (249) (249) - (3,370) (3,370) -
------- ------- ------ --------- -------- --------
November 30, 1997 1,805 1,805 - 18,520 18,520 -
======= ======= ====== ========= ======== ========
Proved developed reserves
(producing and non-producing):
November 30, 1995 1,384 1,384 - 11,282 11,282 -
======= ======= ====== ========= ======== ========
November 30, 1996 1,211 1,211 - 15,758 15,758 -
======= ======= ====== ========= ======== ========
November 30, 1997 1,333 1,333 - 16,122 16,122 -
======= ======= ====== ========= ======== ========
</TABLE>
5
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Proved Developed Producing Reserves
As of November 30, 1997, Columbus has approximately 1,042,000 barrels of
proved developed producing oil and condensate in the United States most of which
are attributable to primary recovery operations. Producing oil properties in
North Dakota, Montana and Texas account for over 95% of the reserves in the
proved developed producing category.
The gas producing properties owned by Columbus are located in Texas, North
Dakota, Louisiana, Oklahoma and Montana and contain 12.2 billion cubic feet of
proved developed producing gas reserves.
The reserves in this category can be materially affected positively or
negatively by either currently prevailing or future prices because they
determine the economic lives of the producing wells.
Proved Developed Non-Producing Reserves
The reserves in this category are located in the states of Texas,
Louisiana, Montana and North Dakota. Generally, these are reserves behind the
casing in existing wells with recompletion required before commencement of
production or else are in wells being completed and/or completed but awaiting
pipeline connections at year end.
Columbus' non-producing reserves equal 292,000 barrels of oil, or 16% of
its total proved oil reserves, and 3.9 billion cubic feet of natural gas, or 21%
of its total proved natural gas reserves.
Proved Undeveloped Reserves
Columbus' proved undeveloped reserves were approximately 472,000 barrels
and 2.4 billion cubic feet of natural gas. Almost all of the oil reserves in
this category are in Montana, North Dakota and Texas. All of the proved
undeveloped gas reserves are attributable to undrilled locations offsetting
production in Webb, Zapata and Jim Hogg Counties, Texas, Montana and North
Dakota.
These reserves are expected to either be developed during 1998 or in future
when oil prices again stabilize at levels which will yield a satisfactory rate
of return on investment when developed.
6
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Standardized Measure
The schedule of Standardized Measure of Discounted Future Net Cash Flows
(the "Standardized Measure") is presented below pursuant to the disclosure
requirements of the Securities and Exchange Commission ("SEC") and Statement of
Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing
Activities" (SFAS- 69) for such information. Future cash flows are calculated
using year-end oil and gas prices and operating expenses, and are discounted
using a 10% discount factor.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO ESTIMATED PROVED OIL AND GAS RESERVES
(thousands of dollars)
1997 1996 1995
---- ---- ----
Future oil and gas revenues $79,381 $98,555 $58,083
Future cost:
Production cost (21,856) (25,620) (18,214)
Development cost (5,401) (4,264) (4,743)
Future income taxes (11,531) (14,198) (5,466)
------- ------- -------
Future net cash flows 40,593 54,473 29,660
Discount at 10% (10,422) (16,313) (8,268)
------- ------- -------
Standardized measure of discounted future net
cash flows $30,171 $38,160 $21,392
======= ======= =======
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
FOR THE THREE YEARS ENDED NOVEMBER 30, 1997
(thousands of dollars)
United
Total States Canada
----- ------ ------
Balance, December 1, 1994 $32,775 $21,772 $11,003
Sale of oil and gas net of production costs (5,311) (4,926) (385)
Net changes in prices and production costs (3,574) 1,294 (4,868)
Purchase of reserves 1,693 1,693 -
Sale of reserves (8,498) (8,498)
Extensions, discoveries and other additions 616 616 -
Revisions to previous estimates (2,648) (2,642) (6)
Previously estimated development costs
incurred during the period 716 716 -
Changes in development costs 111 656 (545)
Accretion of discount 2,501 2,501 -
Other (664) (751) 87
Change in future income taxes 3,675 463 3,212
-------- ------- ------
Net increase (decrease) (11,383) (380) (11,003)
-------- ------- ------
Balance, November 30, 1995 21,392 21,392 -
(continued)
7
<PAGE>
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
FOR THE THREE YEARS ENDED NOVEMBER 30, 1997 - (continued)
(thousands of dollars)
United
Total States Canada
----- ------ ------
Sale of oil and gas net of production costs $(7,556) $(7,556) $ -
Net changes in prices and production costs 19,446 19,446 -
Purchase of reserves 5,158 5,158 -
Sale of reserves (229) (229) -
Extensions, discoveries and other additions 8,309 8,309 -
Revisions to previous estimates (4,905) (4,905) -
Previously estimated development costs
incurred during the period 729 729 -
Changes in development costs 570 570 -
Accretion of discount 2,416 2,416 -
Other (1,571) (1,571) -
Change in future income taxes (5,599) (5,599) -
-------- ------- ------
Net increase 16,768 16,768 -
-------- ------- ------
Balance November 30, 1996 38,160 38,160 -
-------- ------- ------
Sale of oil and gas net of production costs (10,708) (10,708) -
Net changes in prices and production costs (10,502) (10,502) -
Sale of reserves (1,320) (1,320) -
Extensions, discoveries and other additions 9,660 9,660 -
Revisions to previous estimates (710) (710) -
Previously estimated development costs
incurred during the period 1,089 1,089 -
Changes in development costs 229 229 -
Accretion of discount 4,653 4,653 -
Other (1,620) (1,620) -
Change in future income taxes 1,240 1,240 -
-------- ------- ------
Net increase (7,989) (7,989) -
-------- ------- ------
Balance November 30, 1997 $30,171 $30,171 $ -
======== ======= ======
The standardized measure is intended to provide a standard of comparable
measurement of the Company's estimated proved oil and gas reserves based on
economic and operating conditions existing as of November 30, 1997, 1996 and
1995. Pursuant to SFAS-69, the future oil and gas revenues are calculated by
applying to the proved oil and gas reserves the oil and gas prices at November
30 of each year relating to such reserves. Future price changes are considered
only to the extent provided by contractual arrangements in existence at year
end. Production and development costs are based upon costs at each year end.
Future income taxes are computed by applying statutory tax rates as of year
end with recognition of tax basis, net operating loss carryforwards,
8
<PAGE>
depletion carryforwards, and investment tax credit carryforwards as of that date
and relating to the proved properties. Discounted amounts are based on a 10%
annual discount rate. Changes in the demand for oil and gas, price changes and
other factors make such estimates inherently imprecise and subject to revision.
Discounted future net cash flows before income taxes for U.S. reserves were
$37,301,000 in 1997, $46,530,000 in 1996, and $24,163,000 in 1995. As required
by SFAS-69, the future tax computation appearing in the above table does not
consider the Company's annual interest expenses and general and administrative
expenses nor future expenditures for intangible drilling costs. Because of these
factors, the tax provisions are not truly representative of the expected lower
future tax expense to the Company so long as it remains an active operating
company.
The reserve and standardized measure tables prescribed by the SEC and
presented above are prepared on the basis of a weighted average price for all
properties as of each year end. At November 30, 1997 the U.S. crude oil price
(including natural gas liquids) was $18.36 per barrel and the natural gas price
was $2.50 per thousand cubic feet. The SEC requires that this computation
utilize those year end prices and expenses which are then held constant, except
for contractual escalations, over the life of the property.
The calculation of discounted future cash flows can be materially affected
by being compelled to use only those prices that happen to be effective on
November 30 each year (Columbus' fiscal year end) because of price volatility.
Mandatory usage of prices which happen to prevail on a single date can have an
inordinate influence on year-end reserves as well as on the resulting year to
year change that a company reports for discounted future net cash flows
determined using this standardized measure calculation. Management has long
advocated using a weighted average of prices actually received throughout the
year to make this standardized measure calculation less susceptible to the
impact of wide monthly fluctuations in prices which have occurred so frequently
in recent years. Even using weighted average annual prices still may or may not
be very indicative of future cash flows because average prices may vary widely
in future fiscal years. This most recent 1997 fiscal year is a good example of
why an average price would be preferable in management's opinion as year end
prices for natural gas and crude oil were significantly different from the
average annual prices received.
Outside Consultant's Report
An outside consulting firm, Reed Ferrill & Associates, was retained for the
purpose of preparing a report covering the reserves of the Company's properties
and a future production forecast using constant prices as of November 30, 1997,
1996 and 1995. The reports on the reserves of the properties located in the
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Berry Cox field in Texas were prepared by Huddleston & Co., Inc., another
outside consulting firm. These reports are prepared each year as required by the
Company's bank line of credit.
Production
Columbus' net oil and gas production for each of the past three fiscal
years is shown on the following table:
Fiscal Year
---------------------------------
1997 1996 1995
---- ---- ----
USA
Oil-barrels 249,000 246,000 225,000
Gas-Mmcf 3,370 2,686 2,033
CANADA
Oil-barrels - - 11,000
Gas-Mmcf - - 446
-------- -------- --------
TOTAL
Oil-barrels 249,000 246,000 236,000
Gas-Mmcf 3,370 2,686 2,479
During the fiscal year 1997, Columbus filed Form EIA23 with the Energy
Information Agency which required disclosure of oil and natural gas reserve data
for wells operated by Columbus. The reserve data reported was for calendar year
1996. This data was reported on a gross operated basis inclusive of royalty
interest and, therefore, does not compare with Columbus' net reserves reported
for 1996.
Average price and cost per unit of production for the past three fiscal
years are as follows:
Fiscal Year
---------------------------------
1997 1996 1995
---- ---- ----
Average sales price per barrel of oil
USA $19.62 $19.42 $16.75
Canada (U.S.$)(1) - - 11.61
Total Company 19.62 19.42 16.48
Average sales price per Mcf of gas
USA $ 2.65 $ 2.15 $ 1.71
Canada (U.S.$) - - 1.09
Total Company 2.65 2.15 1.60
Average production cost per
equivalent barrel
USA $ 3.83 $ 4.35 $ 4.16
Canada (U.S.$) - - 2.89
Total Company 3.83 4.35 3.99
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Natural gas converted to oil at the ratio of six Mcf of natural gas to one
barrel of oil. Production costs for fiscal years 1997, 1996 and 1995 include
production taxes.
(1) Natural gas liquids are combined with oil.
Developed Properties
A summary of the gross and net interest in producing wells and gross and
net interest in producing acres is shown in the following table:
November 30, 1997 Gross Net
- ----------------- ------------- -----------
Oil Gas Oil Gas
--- --- --- ---
Wells - USA 79 154 19 19
Acres - USA 35,118 9,747
Undeveloped Properties
The following table sets forth the Company's ownership in undeveloped
properties:
November 30, 1997 Gross Acres Net Acres
- ----------------- ----------- ---------
Louisiana 40,632 4,086
Montana 11,279 7,644
New Mexico 840 630
North Dakota 2,070 419
Oklahoma 320 108
Texas 2,591 1,005
------ ------
Total Undeveloped Properties 57,732 13,892
====== ======
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Drilling Activities
The Company engages in exploratory and development drilling in association
with third parties, typically other oil companies. Actual drilling operations
are not conducted by the Company and are usually carried out by third party
drilling contractors, but the Company may act as operator of the projects. The
following table gives information regarding the Company's drilling activity in
its last three fiscal years.
Year Ended November 30,
-----------------------------------------------------------
1997 1996 1995
--------------- --------------- --------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
EXPLORATORY
Wells Drilled:
Oil 2 1.45 - - 1 .68
Gas 1 .37 - - - -
Dry 1 .34 2 .68 - -
DEVELOPMENT
Wells Drilled:
Oil 4 1.91 2 1.00 1 .19
Gas 18 2.71 14 2.60 8 .62
Dry 3 .65 6 2.95 3 1.16
TOTAL
Wells Drilled:
Oil 6 3.36 2 1.00 2 .87
Gas 19 3.08 14 2.60 8 .62
Dry 4 .99 8 3.63 3 1.16
-- ---- -- ---- -- ----
Total 29 7.43 24 7.23 13 2.65
== ==== == ==== == ====
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Current Activities
The Company continued a development program on its properties and expanded
its exploration efforts during fiscal 1997. Expenditures by the Company reached
a record $10,088,000 for development and exploration drilling primarily on its
oil-oriented properties in the Williston Basin of Montana and natural gas prone
areas east of Houston and in Webb and Zapata Counties near Laredo, Texas.
However, the Austin Chalk trend of mid-Louisiana was a new province for
Columbus' exploratory efforts and unfortunately, Columbus' share of the first
well exceeded expected costs by over $1,500,000. Fortunately, exploratory and
development activity in the onshore upper Gulf Coast area continued to be EGY's
most successful core area from the standpoint of both crude oil and natural gas
reserve and productivity additions.
A review of the more significant operations follow below and have been
segregated into Columbus' primary areas of operations.
South Texas - Laredo Area
- -------------------------
As the second most important source of lease level cash flow for the past
several years, this area remains its most important as a source of operational
income. The Company serves as operator of in excess of 100 natural gas wells in
various fields from the southern city limits of Laredo to the B.R. Cox field in
Jim Hogg, County, almost 80 miles to the south. Columbus owns working interests
which range from 1% to 53% in the wells which it operates and less than 10% WI
in those wells in which it does not operate.
At least one drilling rig was utilized continuously throughout the year to
drill infill and extension locations that had been identified by a 3-D seismic
program conducted in 1995 and 1996. This suggested there were numerous new fault
blocks which had not been previously drained by offset wells in one or more Lobo
sands that produce in the area and would require drilling 40 to 50 new locations
in order to exploit those reserves. A development program was begun during 1996
with 12 wells drilled and was continued throughout 1997 with participation in 18
additional wells resulting in three (0.65 net) dry holes and 15 (1.74 net)
successful gas wells. Two (0.11 net) wells were in progress at year end which
have since been completed as gas wells.
In the B.R. Cox field, Columbus' working interest in the five remaining
wells (two active) on the Ruben Gonzalez producing property was sold for a net
of $750,000 effective as of October 1, 1997. No new recompletions into new gas
zones in wells on the remaining leases were undertaken in 1997 by Columbus as it
awaited pre-payment for expected costs on one planned project from the largest
working interest owner who had been very slow paying its prior operating bills.
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Sralla Road Field Area - Harris County, Texas
- ---------------------------------------------
This operational area continues to be Columbus' primary source of field
level cash flow and is expected to be reasonably important for a few more years.
During fiscal 1997 one (0.78 net) operated gas well, the James-Fielder #1, was
completed in the upthrown fault block of the West Jackson Sralla Road field and
extended the productive limits of the gas cap by another mile southwest. It had
a similar thickness to other Jackson sand wells in the field and has since
produced at its state-assigned allowable of about 1,300 Mcfd. An offset well to
the Fielder and Wiggins units, the Hargrove #2 (0.13 net), is a non-operated gas
well that was completed shortly thereafter and has been selling its monthly
allowable also. In addition, that same operator drilled two other gas cap wells
in the same general area but where Columbus had no interest. They also extended
the field's oil zone limits by one mile to the northeast of the Company's
original Ferguson #1 discovery oil well. As the fiscal year closed, that
extension oil well was being offset by EGY's 67%-owned Waitkus B #2 (0.67 net)
which has subsequently been completed as a successful flowing oil well in
January at about 50 BOPD.
About 20 miles southeast of the Sralla Road field, the Company participated
in an exploratory test of a 2-D seismic anomaly in search of gas in the Frio 16
sand at 9,000 feet. It was located in a separate fault block which was adjacent
to the old Anahuac field in Chambers County, Texas that produced several hundred
million barrels of oil from uphole Frio sands over several decades. The Syphrett
Heirs #1 wildcat resulted in a natural gas discovery in the Frio 16 sand after
which a production unit of 480 acres in size was agreed upon. The Company
initially owned about 37% WI which was subject to a 25% reduction after it fully
recovered all of its costs of acreage plus drilling and completion costs of this
initial well. Excellent log and gas shows in the mud were encountered so
Columbus assumed operatorship, set casing and built a gathering system and a
pipeline connection in advance of perforating only ten feet of a 40-foot gross
interval of F-16 sand. The well was tested in early July at a daily rate of 4.6
million cubic feet of gas and 90 barrels of condensate through a 14/64ths choke
with a flowing tubing pressure of 4,950 psig. The well has been restricted to
about 120 million cubic feet per month but nevertheless payout occurred in
November thereby reducing Columbus' working interest to 27.75%.
A similar interest is owned in an additional 600 acres of prospective
acreage to the south and east of the discovery and will require its own
exploratory test as it is a separate fault block. A well is expected to be
commenced early in 1998 and may be drilled as deep as 11,000 feet to also test
the underlying Vicksburg formation. A gas discovery was made in that zone about
two miles east of the Syphrett fault block while a dry hole has been drilled to
14
<PAGE>
that formation at a location closer to this southeast acreage block. The Frio 15
sand is considered prospective for oil production at a structurally higher
position in the Syphrett well discovery fault block and could also be productive
in the southeast block.
Williston Basin Area
- --------------------
Most of 1997's efforts in this area were related to workovers, short radius
lateral recompletions, 3-D seismic programs, plus drilling two new deep wells
because crude oil prices stayed consistently above $17 per barrel throughout
1996 and 1997. This was further supported by futures swaps but unfortunately
this practice was not repeated so crude prices (which have fallen dramatically
thus far in fiscal 1998) have not been protected by swaps.
A 3-D seismic effort which included the Southeast Froid field had
previously been conducted over several sections during the last quarter of 1996
which pinpointed the highest structural location at which to drill a 12,000 foot
replacement oil well to the Red River formation in that field. It also gave
indications that another structure existed west of that field so additional
leases were acquired bringing the total leaseholds owned to over 2,000 acres
with a 90% WI. Supplemental 3-D seismic coverage was undertaken in the spring of
1997 to further delineate that potential structure as well as follow up on other
leads including a Tyler sand river bed channel which appeared to meander through
the acreage around those deep Paleozoic highs.
During 1997's second quarter, the 90% WI-owned McCabe #1-X Red River zone
replacement well was drilled and completed in 20 feet of porosity in that
formation. It also encountered several shows of oil in other horizons uphole
before production casing was set. After perforating, the 1-X well was initially
tested on pump at the rate of 86 barrels of oil per day but also produced a like
amount of water despite the fact this location was about 10 feet structurally
higher than the initial McCabe #1 Red River discovery well which it replaced.
The latter well was then recompleted as an oil discovery in the Winnepegosis
formation at about 11,100 feet following removal of junk which plugged the
casing at about 9,400 feet. It initially pumped oil at rates of 116 to 141
barrels per day and water of 51 to 85 barrels per day. While each of those two
wells added materially to third quarter oil production, steadily increasing
water cuts during the fourth quarter have reduced their contribution to this
area's daily oil production.
Following completion of the second 3-D seismic program in late spring, an
exploratory Red River test well location was staked on one of several small
bumps on a fairly broad closure of almost a section in size. Therefore one or
more potential locations on this broad structure might be exploited now that the
initial test well, the McCabe Farms #1-4 wildcat, proved to be productive. No
drill stem tests were taken in one well while drilling uphole formations but a
possible gas zone was encountered in a porous zone in the Mission Canyon which
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<PAGE>
is behind pipe. Excellent porosity and oil shows were encountered in the Red
River "C" formation, casing was set and the well was completed with 21 feet of
perforations in an interval from 11,910 to 11,937. Through a 17/64ths inch
choke, the 90% owned McCabe Farms #1-4 flowed oil on initial test at the rate of
135 barrels per day with a water cut of 30% and a flowing tubing pressure of 150
psi. Since this well was not finally completed until early December, it will be
considered as a fiscal 1998 discovery although most of the costs were incurred
as part of 1997 fiscal year capital expenditures.
Immediately following this completion the 69%-owned McCabe #3-2 exploratory
well was drilled to the Tyler formation at a depth of 7,200 feet but it proved
to be a dry hole. While the meandering river bed seismic feature was confirmed,
the cut made by river had subsequently been filled in by shale and lime with
only a very limited amount of sand present as opposed to the 100 foot that had
been expected.
Two short radius laterals in Columbus' 100% owned Lien lease in the west
Mondak field were undertaken in the Lien #1 and Lien #3 wells which were
marginal Mission Canyon oil producers. The first effort involved drilling a 921
foot lateral out of the cased hole in the Lien #3 well at a depth of about 8,900
feet. Unfortunately, this lateral only encountered very limited fracturing.
After much higher initial oil production rates, the well appears to have settled
around 17 barrels of oil and 60 barrels of water per day. The Lien #1 lateral
was next undertaken near the end of the fiscal year. A record horizontal hole of
1,550 feet was accomplished but again this lateral did not encounter a
recognizable vertical fracture system. Thus far the Lien #1 appears not to be
any more productive than the Lien #3 despite the longer lateral interval but
there have been problems with the downhole pump so this is not yet a final
appraisal of the well's productivity.
Oklahoma - Anadarko Basin
- -------------------------
There were three (1.02 net) development Morrow sand oil wells completed in
Beaver County, Oklahoma all of which had excellent appearance on electric logs
but only resulted in marginal oil producers. This is primarily due to a
combination of water cuts in excess of 50% plus unstable frac sand which has
plugged perforations and reduced total fluid productivity to levels only a
fraction of the initial swab rates seen following frac treatment.
Goudeau Prospect - Avoyelles & St. Landry Parishes, Louisiana
- -------------------------------------------------------------
As previously reported in Form 10-K and various quarterly and interim
special reports, Columbus has a 12.5% working interest in a three township Area
of Mutual Interest (AMI) in mid-Louisiana covering 41,000 gross acres of
leaseholds which overlie the geo- pressured, fractured Austin Chalk formation
below 15,000 feet in depth. A good portion of this block was assembled by a
co-venture group which included EGY and 75% was then sold to Belco Oil & Gas.
16
<PAGE>
Terms included a modest profit on acreage plus an after payout carried 25%
interest in a vertical well to be drilled from grass roots to 15,000 feet and
included updip and downdip horizontal legs approximately 3,000 to 4,000 feet in
length. This deal was subsequently modified to permit the use of an existing
mutually- owned abandoned but cased vertical hole from which to drill two
laterals at no up front costs to Columbus or its co-venturers to be followed
later by a no cost vertical hole portion to be drilled at a second location. The
Morrow #23-1H's operations began in February with Belco choosing to drill a
3,000-foot north updip lateral first. Belco purposely elected to drill laterally
below the base of the Austin Chalk for reasons not clear to, and despite the
objections of, the co-venture group and this lateral resulted in a dry hole. As
a consequence, Belco then drilled a piggyback lateral about 100 feet vertically
higher in the prospective pay section which penetrated numerous shows and
fractures throughout this 3,100-foot horizontal hole. Belco was disappointed
with its production test from this updip lateral which over a 66-hour period
averaged a high water cut of about 70% in addition to varying rates of crude oil
and natural gas. The last few hours of test showed a total fluid rate of about
66 barrels per hour of which 21% was oil (over 12 BPH) and 600,000 cubic feet of
natural gas per day.
Following that test, Belco proposed to move the drilling rig off of that
location without drilling the obligatory 4,000-foot southerly direction downdip
lateral. There was immediate strong objections to that proposal by the
co-venturers which was eventually settled by Belco relinquishing all of its
right, title and interest in the cased well bore, the new updip 3,000-foot
lateral and the 1,960-acre spacing unit to the co-venturers who thereupon took
over operations. Numerous problems were encountered while attempting to drill
this downdip lateral not the least of which included encountering high bottom
hole pressures which exceeded the maximum attainable weighting of the clear
drilling fluid being used and was needed to maintain control over the well. As a
result, only 1,300 feet of the proposed 4,000-foot southerly downdip lateral
could be drilled and the well had to be killed with a conventional
barite-weighted mud system after replacing the clear drilling fluid. This change
created a severe lost circulation problem so that any further efforts to finish
the entire 4,000-foot lateral were ceased. The co-venturers generally agreed to
make another attempt to drill a new 4,000-foot downdip lateral from a new casing
window after this 1,300-foot downdip lateral and the updip 3,100-foot lateral
had been depleted.
Subsequently, numerous other problems were encountered during the
completion operations. These included packer problems, inability to push the
liner out to the full 1,300 feet length of the lateral, inexperienced crews,
faulty or improperly serviced rental equipment from major service companies,
several poor engineering consultant's decisions, drilling rig equipment
failures, disputes amongst the co-venturers on procedures, etc. The final blow
occurred when a roughneck dropped a five inch bolt in the hole which blocked the
17
<PAGE>
top of the packer and contributed to several additional days of rig and rental
equipment expenses. A "jerry-rigged" completion had to be designed which at
least permitted the well to produce from the downdip lateral only. It is
impossible to predict how this will finally affect eventual recovery from the
lateral but well cost overruns to the 100% interest exceeded $2,000,000.
Fortunately, Columbus only owns 55% WI of the completed well and drilling unit
so that these significant cost overruns did not have to be entirely absorbed by
it.
Finally, an initial potential of the 1,300-foot downdip lateral only
resulted in the Morrow #23-1H producing for a 26-hour clean-up period followed
by a 24-hour test period during which the well flowed 560 barrels of 41o API
gravity oil, 831 Mcf of natural gas and 1,691 barrels of what appeared to be a
mixture of formation salt water and the clear calcium bromide drilling fluid
lost during drilling operations.
A gas gathering line was laid to a nearby transmission system about 7,500
feet to the south and a tank battery, separator, treater, plus other surface
equipment was installed. Also, a shallow water disposal well has been drilled
and cased. The well was placed on production late in November on various small
sizes of surface chokes which yielded rates which have ranged from 60 to 200
barrels of oil per day with water cuts from 70% to 80% and a flowing tubing
pressure of 750 to 950 psi. It is a bit early to forecast with any accuracy the
amount of oil that will be recovered from this downdip lateral, but through the
first 35 days to December 31, 1997, it had produced 5,156 barrels of oil, an
estimated 26,000 barrels of water and 4,179,000 cubic feet of natural gas. It is
planned to first try to essentially deplete the short downdip lateral before
attempting removal of the junk and bridge plug above the updip lateral which
will allow that lateral to be produced. There is no forecast of when a drilling
rig might be contracted for another attempt at drilling a 4,000-foot downdip
lateral.
At least one additional well in the AMI is proposed to be promoted at the
second drillsite along with a sale of the AMI acreage which remains. However,
the co-venturers have already determined not to exercise any of the remaining
option acreage as no profit would be realized from Belco. Should the Morrow
#23-1H not perform as currently forecasted from the two existing laterals, then
it is highly unlikely further development by drilling one or more new laterals
from this Morrow #23-1H well bore will ever be undertaken by this group.
Significant impairment charges for this area and well of $1,475,000 have already
been recognized in fiscal 1997 by the Company and this has reduced net book
value significantly and will lower depletion charges per barrel for this area in
1998.
18
<PAGE>
Columbus' own expenditures (before impairment charges) in this prospect
through November 30, 1997 totaled $939,000 for undeveloped leaseholds and
$2,879,000 for interests in producing wells with most of the latter costs
related to the Morrow #23-1H completion.
Titles
The Company is confident that it has satisfactory title to its producing
properties which are held pursuant to leases from third parties and have been
examined on several occasions to determine their suitability to serve as
collateral for bank loans. Oil and gas interests are subject to customary
interest and burdens, including overriding royalties and operating agreements.
Titles to the Company's properties may also be subject to liens incident to
operating agreements and minor encumbrances, easements and restrictions.
As is customary in the oil and gas industry, the Company does not regularly
investigate titles to oil and gas leases when acquiring undeveloped acreage.
Title is typically examined before any drilling or development is undertaken by
checking the county and various governmental records to determine the ownership
of the land and the validity of the oil and gas leases on which drilling is to
take place. The methods of title examination adopted by the Company are
reasonably calculated, in the opinion of the Company, to insure that production
from its properties, if obtained, will be readily salable for the account of the
Company. As stated above, certain of the Company's producing properties have
been subject to independent title investigations as a consequence of bank loans
obtained and have been accepted for such purposes. Insofar as is known to the
Company, there is no material litigation pending or threatened pertaining to its
proved acreage.
The producing and non-producing acreages are subject to customary royalty
interests, liens for current taxes, and other burdens, none of which, in the
opinion of the Company, materially interfere with the use of or adversely affect
the value of such properties.
Competition, Marketing and Customers
Competition and Marketing. The oil and gas industry is highly competitive.
Major oil and gas companies, independent producers with public drilling and
production purchase programs and individual producers and operators are active
bidders for desirable oil and gas properties as well as for the equipment and
labor required to operate such properties. Many competitors have financial
resources, staffs and facilities substantially greater than those of the
Company. A ready market for the oil and gas production is, to a limited extent,
dependent upon the cost and availability of alternative fuels as well as upon
the level of consumer demand and domestic production of oil and gas; the amount
19
<PAGE>
of importation of foreign oil and gas; the cost and proximity to pipelines and
other transportation facilities; the regulation of state and federal
authorities; and the cost of complying with applicable environmental
regulations.
All production of crude oil and condensate by the Company is sold to others
at field prices posted by the principal purchasers of crude oil in the areas
where the producing properties are located. In the Company's judgment,
termination of the arrangements under which such sales are made would not
adversely affect its ability to market oil and condensate at comparable prices.
During recent years, the posted prices were directly affected by the
fluctuations in the supply and price of imported crude oil as well as by trading
of oil futures.
A very limited amount of the natural gas produced by the Company is being
sold at the well head under long-term contracts. Following deregulation of
natural gas, excesses of domestic supply over demand, plus competition from
alternate fuels caused Columbus, through CGSI, to take a much more active role
in marketing its own gas along with gas owned by third parties.
Customers. Sales to three purchasers of crude oil and natural gas, which
amounted to more than 10% of the Company's combined revenues for the years ended
November 30, 1997, 1996 and 1995, are set forth in Note 3 to Notes to the
Consolidated Financial Statements. In the opinion of management, a loss of a
customer has not to date, and should not in the future, materially affect the
Company since the nature of the oil and gas industry is such that alternative
purchasers are normally available on very short notice.
Government Regulations
The development, production and sale of oil and gas is subject to various
federal, state and local governmental regulations. In general, regulatory
agencies are empowered to make and enforce regulations to prevent waste of oil
and gas, to protect the correlative rights and opportunities to produce oil and
gas between owners of a common reservoir, and to protect the environment.
Matters subject to regulation include, but are not limited to, discharge permits
for drilling operations, drilling bonds, reports concerning operations, the
spacing of wells, unitization and pooling of properties, taxation and
environmental protection. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas.
The Company believes that the environmental regulations, as presently in
effect, will not have a material effect upon its capital expenditures, earnings
or competitive position in the industry. Consequently, the Company does not
anticipate any material capital expenditures for environmental control
facilities for the current year or any succeeding year. No assurance can be
20
<PAGE>
given as to the future capital expenditures which may be required for compliance
with environmental regulations as they may be adopted in future. The Company
believes, however, that it is reasonably likely that the trend in environmental
legislation and regulations will continue to be towards stricter standards. For
instance, legislation previously considered in Congress would amend the Resource
Conservation and Recovery Act to reclassify oil and gas production wastes as
"hazardous waste," the effect of which would be to further regulate the
handling, transportation and disposal of such waste. If similar legislation were
to pass, it could have a significant adverse impact on the operating costs of
the Company, as well as the oil and gas industry in general.
Operating Hazards
The oil gas business involves a variety of operating risks, including the
risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally
pressured formations, and environmental hazards such as oil spills, gas leaks,
ruptures and discharge of toxic gases, the occurrence of any of which could
result in substantial losses to the Company due to injury and loss of life,
severe damage to and destruction of property, natural resources and equipment,
pollution and other environmental damage, clean-up responsibilities, regulatory
investigation and penalties and suspension of operations. The Company maintains
insurance against some, but not all, potential risks; however, there can be no
assurance that such insurance will be adequate to cover any losses or exposure
for liability. Furthermore, the Company cannot predict whether insurance will
continue to be available at premium levels that justify its purchase or whether
insurance will be available at all. Generally, the Company has elected to not
obtain blow-out insurance when drilling a well, except for deep high pressure
wells or when required such as within city limits.
Natural Gas Controls
The Federal Energy Regulatory Commission ("FERC") has issued several rules
which encourage sales of gas directly to end users and provides open access to
existing pipelines by producers and end users at the highest possible prices
that can be negotiated. All price controls were terminated as of January 1,
1993. On April 8, 1992, FERC issued Order No. 636 which has essentially
restructured the interstate gas transportation business. The stated purpose of
Order 636 was to improve the competitive structure of the pipeline industry and
maximize consumer benefits from the competitive wellhead gas market and to
assure that the services non-pipeline companies can obtain from pipelines is
comparable to the services pipeline companies offer to their customers. The
Order is complex and, while it faces challenges in court, it has been fully
activated following a rehearing with minimum modification and subsequent
reissuance as FERC Order No. 636A. The Company is not able to predict the extent
to which this very complex order will change the industry in the long term but
21
<PAGE>
short term it has led to much more competitive markets and raised serious
questions about whether gathering systems of interstate pipelines can be sold
off and totally escape regulation.
Item 3. 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.
The Company's officers and directors are indemnified by contractual
agreement with each individual, as well as by the Articles of Incorporation of
Columbus as provided in and in accordance with the Colorado Corporation Code, as
amended, of the State of Colorado.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1997, no matters were submitted to a vote of
security holders.
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<PAGE>
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
The common stock of Columbus commenced trading on the American Stock
Exchange on March 11, 1993. The common stock previously traded on the American
Stock Exchange Emerging Companies Marketplace since July 30, 1992, and on the
Pacific Stock Exchange since April 15, 1988. The reported high and low sales
prices for the periods ending below were as follows:
High(1) Low(1)
---- ---
1998:
December 1, 1997 through
January 31, 1998 $ 9.00 $ 8.325
1997:
First quarter $ 8.80 $ 6.90
Second quarter 8.40 6.75
Third quarter 8.625 7.50
Fourth quarter 9.125 7.75
1996:
First quarter $ 4.60 $ 4.00
Second quarter 6.40 4.30
Third quarter 9.10 5.60
Fourth quarter 8.70 7.60
1995:
First quarter $ 6.45 $ 5.80
Second quarter 6.60 5.90
Third quarter 6.30 5.10
Fourth quarter 5.40 4.50
(1) Price per share amounts have been adjusted for the 10% stock dividend
distribution to shareholders of record on February 24, 1995 and the
five-for-four stock split on May 27, 1997.
As of January 31, 1998 the reported closing sales price of Columbus common
stock was $8.625 per share.
As of November 30, 1997, there were approximately 461 holders of record of
Columbus' common stock and an estimated 1,100 or more beneficial owners who hold
their shares in brokerage accounts.
The Company has never paid any cash dividends on its common stock and does
not contemplate the payment of cash dividends since it plans to use earnings
available for its drilling, development and acquisition programs and excess cash
flow has been used to acquire treasury shares that can be used for acquisitions
or stock dividends. Payment of future cash dividends would also be dependent on
earnings, financial requirements and other factors.
23
<PAGE>
Item 6. SELECTED FINANCIAL DATA
The table below sets forth selected historical financial and operating data
for the Company and its consolidated subsidiaries for the years indicated. The
historical data for each of the years in the five-year period ended November 30,
1997, were derived from the financial statements of the Company which have been
audited by Coopers & Lybrand L.L.P., independent accountants. This information
is not necessarily indicative of the Company's future performance. The
information set forth below should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations," and
the Company's Financial Statements and notes thereto, included elsewhere herein.
<TABLE>
<CAPTION>
Year Ended November 30,
----------------------------------------------------------------------------
1997 1996 1995(a) 1994 1993
---- ---- ---- ---- ----
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Operating data:
Revenues $ 15,096 $ 11,815 $ 9,400 $13,141 $12,913
Loss on asset disposition,
impairment of long-lived
properties, and abandonment (2,179) (165) (3,055) - (258)
Earnings (loss) before cumulative
effect of accounting change 2,167 2,098 (1,495) 2,190 2,814
Cumulative effect of accounting
change - - - - 992
------- -------- -------- ------- -------
Net earnings (loss) 2,167 2,098 (1,495) 2,190 3,806
======= ======== ======== ======= =======
Earnings (loss) per share (primary):
Before cumulative effect of
accounting change $ .55 $ .54 $ (.38) $ .54 $ .66
Cumulative effect of
accounting change - - - - .23
------- -------- -------- ------- -------
Net earnings (loss)(b) .55 .54 (.38) .54 .89
======= ======== ======== ======= =======
Fully diluted earnings per share N/A .51 N/A N/A N/A
======= ======== ======== ======= =======
Average number of common
and common equivalent
shares outstanding:
Primary 3,908 3,872 3,928 4,087 4,255
======= ======== ======== ======= =======
Fully diluted N/A 4,086 N/A N/A N/A
======= ======== ======== ======= =======
Cash flow data(d):
Cash from operating activities $ 8,638 $ 5,638 $ 3,929 $ 6,194 $ 5,540
Cash used in investing activities $(7,294) $ (6,320) $ (119) $(7,194) $(5,652)
Cash provided by (used in)
financing activities $ (883) $ 664 $ (4,223) $ 519 $ 79
Cash flow before changes in
operating assets and liabilities $ 9,132 $ 6,340 $ 3,920 $ 6,254 $ 6,468
Discretionary cash flow $ 9,672 $ 6,658 $ 4,096 $ 6,715 $ 6,633
Balance sheet data:
Total assets $26,135 $ 21,625 $ 18,321 $24,955 $22,938
Long-term debt, excluding
current maturities - bank debt $ 2,200 $ 2,200 $ 1,600 $ 4,200 $ 3,200
Stockholders' equity $17,958 $ 16,225 $ 13,186 $16,202 $14,400
</TABLE>
24
<PAGE>
(a) Does not include results of CEC Resources Ltd. after its divestiture on
February 24, 1995.
(b) Reflects restated amounts for 1993 through 1996 after stock dividends and
stock split.
(c) No cash dividends have been declared or paid in any period presented.
(d) See discussion of cash flows in "Management's Discussion and Analysis of
Financial Condition and Results of Operations".
Item 7. 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.
The information below and elsewhere in this Form 10-K 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.
Liquidity and Capital Resources
Fiscal 1997 was the best year in the Company's history but this was not
readily evident. This was primarily due to substantial exploration and
impairment charges which significantly reduced net earnings and overshadowed the
boost in natural gas production to record levels. These charges totaled
$2,179,000 which, after being tax effected, reduced net earnings by $1,314,000
or $0.34 per share and resulted in earnings of $2,167,000, or $0.55 per share,
which were 3% higher than last year's net of $2,098,000, or $0.54 per share.
Discretionary cash flow set a record at $9,672,000 in 1997 surpassing 1996's
prior record of $6,658,000 by 45%. Gross revenues and oil and gas sales both set
historical records also.
As of the end of 1997, shareholders' equity had risen to $17,958,000
compared to $16,225,000 at November 30, 1996. Positive working capital of
$722,000 at year end, combined with the Company's anticipated cash flow for
1998, should be a sufficient source of capital to develop undeveloped reserves
and fund a 1998 exploration program. As discussed later, a substantial increase
in the percentage working interest ownership in the Louisiana Austin Chalk
exploratory well required 1997's $7.1 million capital budget to be raised by
over $1 million and after the overruns $1.4 million extra was spent. This
required a short term draw from the Company's bank credit facility until
additional monthly cash flow could restore the amount to $2,200,000 which had
been outstanding at the beginning of the year. The $10,000,000 credit facility
has been primarily targeted by management for acquisitions of oil and gas
properties, but can be used for any legal corporate purpose and is always
available for such expanded operational expenditures.
25
<PAGE>
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 has
fluctuated widely from $3,900,000 to $8,600,000 during the last three years.
This source of funds, with a backup from the available borrowing base under the
Company's credit facility, has provided all of the liquidity required to finance
those three years' oil and gas capital expenditures as well as fund treasury
stock repurchases. However, an important alternative measure of a company's cash
flow (not GAAP but commonly used in the industry) is one determined before
consideration of either working capital changes or deduction of exploration
expenses and is generally known as Discretionary Cash Flow ("DCF"). This is
reported by successful efforts' companies for comparability purposes to the cash
flow results of a majority of independent energy companies who use the full cost
accounting method. With the latter accounting method, all exploration costs are
capitalized, and consequently, do not adversely affect either operating cash
flow or net earnings. Since exploration expenses can be increased or decreased
at management's discretion, DCF is the most comparable to their full cost
accounting results. Columbus' DCF for 1997 was an all time record at $9,672,000
and compares to 1996's $6,658,000 which itself had been the prior record. This
45% improvement directly reflects higher natural gas prices and increased crude
oil and natural gas production over 1996. While DCF is calculated before any
debt retirement requirements, in Columbus' case it does not matter because its
outstanding bank debt requires no principal payments before August 1, 1999.
Interest expense on outstanding debt has recently been fairly insignificant but
is deducted before computing DCF.
Management continues to note its strong exception to the Statement of
Financial Accounting Standards No. 95 which directs that operating cash flow
must only be determined after consideration of working capital changes. We
continue to reflect that position in all public filings and reports based on our
belief such a requirement by GAAP ignores entirely the significant impact on
working capital that the timing of income received for, and expenses incurred on
behalf of, third party owners in wells has on a company which serves as an
operator of properties with only a small working interest therein as in
Columbus' case.
Nevertheless, neither discretionary cash flow nor operating cash flow
before working capital changes may be substituted for net income or cash
available from operations as defined by GAAP. Furthermore, current cash flows do
not necessarily indicate that there will be sufficient funds for future cash
requirements under any of the definitions of cash flow.
At the present time the Company has not hedged either crude oil or natural
gas prices similar to the swaps in prior years discussed below. As a result the
26
<PAGE>
Company's oil and gas revenues are fully exposed to risk of declining prices, as
has occurred during first quarter 1998 but, in turn, can fully benefit from any
price increases, if any, later in 1998.
In prior years Columbus has hedged both natural gas and crude oil prices by
selling a "swap". The swap is matched against the calendar monthly average price
on the NYMEX and settled monthly. Revenues are decreased when the market price
at settlement exceeded the contract swap price or increased when the contract
swap price exceeded the market price. The following table shows the results of
these swaps:
Increase (decrease) in
oil and gas revenues
----------------------
Volume
Description per mo. Period 1997 1996 1995
- ----------- ------- ------ ---- ---- ----
(Mmbtu or bbl)
Natural Gas
- -----------
$2.20/Mmbtu 60,000 3/97-10/97 $(86,400)
Futures Contracts 60,000 10/96-11/96 $ 42,000
$1.74 & $1.88/Mmbtu 120,000 4/96-11/96 $(560,000)
$2.12/Mmbtu 100,000 12/94- 4/95 $283,900
Crude Oil
- ---------
$21.17/bbl 10,000 11/96-10/97 $ 8,900 $ (23,800)
$17.25/bbl with
$19.50/bbl cap 10,000 1/96-12/96 $(22,500) $(232,300)
The Company's natural gas and crude oil swaps were considered financial
instruments with off-balance sheet risk which were in the normal course of
business to partially reduce its exposure to fluctuations in the price of crude
oil and natural gas. Those instruments involved, to varying degrees, elements of
market and credit risk in excess of the amount recognized in the balance sheets.
The Company had no natural gas or crude oil swaps outstanding as of November 30,
1997.
Columbus had outstanding borrowings of $2,200,000 as of November 30, 1997
against its line of credit with Norwest Bank Denver, N.A. which has a borrowing
base of $10,000,000 and is collateralized by oil and gas properties. At the end
of 1997, the ratio of bank debt to shareholders' equity was 0.12 and to total
assets was 0.08. The debt outstanding used a LIBOR option with an average
interest rate of 7.2%. Subsequent to year end through January 31, 1998, the debt
was increased by $600,000 to $2,800,000 as payments were made for late fiscal
1997 and early fiscal 1998 drilling activity. The net increase or decrease in
long-term debt directly affects cash flows from financing activities. This cash
flow item also reflects the purchase of treasury stock discussed below and
benefits from the proceeds from the exercise of stock options.
Working capital at 1997 year end remained positive at $722,000 compared to
$1,966,000 at November 30, 1996. This was achieved despite record capital
27
<PAGE>
expenditures of $9,551,000 for new additions to oil and gas properties as well
as the purchase of 158,014 shares of treasury stock for $1,381,000 during the
year. The change in working capital also reflected a $832,000 reduction in
current deferred income taxes during the year.
The Company has been authorized by the Board of Directors to repurchase its
common shares from the market at various prices during the last several years.
Those repurchases are summarized as follows:
Shares
Fiscal year -------------------------- Average
repurchased As purchased Restated* price*
----------- ------------ --------- -------
1995 243,200 247,730 $7.33
1996 86,100 107,625 $5.33
1997 158,000 179,875 $7.61
*Restated for stock split and stock dividends
As of November 30, 1997 a total of 143,000 shares remained out of the most
recent authorization which may be repurchased at a price not to exceed $8.875
per share. As of January 31, 1998, 49,650 of those shares have been acquired at
an average price of $8.60 per share.
During 1997, capital expenditures were incurred on oil and gas properties
which totaled $9,551,000. This amount differs from the capital expenditure shown
in the Consolidated Statement of Cash Flows which includes cash payments made
during 1997 for 1996 expenditures incurred but not yet paid as of 1996's year
end. Similarly, there have been expenditures accrued in 1997 that will not be
actually paid until 1998. These were primarily for the expanded exploratory
program in the Louisiana Austin Chalk and Montana areas along with development
drilling and recompletions in the South Texas and Gulf Coast areas. The cash
flows from investing activities had an unusual benefit in 1995 from the
$4,075,000 net proceeds received from the divestiture of Resources.
Results of Operations
The Company's 1997 gross revenues of $15.1 million were 28% above 1996's
and was attributable to a record level of natural gas production plus improved
crude oil production generated by the Company's drilling program during 1997. It
should be obvious that 1996 revenues and expenses were not entirely comparable
to 1995's because of the aforementioned divestiture of the Canadian subsidiary
toward the end of the first quarter of 1995. Total Company revenues did increase
by 26% in 1996 but, if Canadian operations were excluded from 1995, the
Company's revenues would have increased by 37%. Higher crude oil and natural gas
prices and production were responsible for the improvement.
28
<PAGE>
Operating income of $3,766,000 in 1997 represented an improvement of only
5% when compared with 1996 because of the aforementioned exploratory charges and
impairment provisions or otherwise that increase would have been 59%. Operating
income of $3,589,000 in 1996 reflected improved revenues but was not comparable
to 1995 which showed a loss of $1,811,000, a direct result of deduction of
impairment losses which are fully discussed below. The operating loss in 1995
also resulted from lower revenues and higher depletion expense following the
Canadian divestiture.
Net earnings during 1997 set a new high for U.S. only operations of
$2,167,000 which surpassed 1996's earnings of $2,098,000. Had there not been the
extremely high non-cash impairment provisions during 1997, all time record net
earnings would have resulted which would have surpassed those years which
included Canada's operations. Contrarily, earnings in 1995, even ignoring the
impairment charge, were at their lowest level since 1991.
Impairments
A non-cash impairment loss of $243,000 for 1997 and $165,000 for 1996
recognized that some marginal Oklahoma development oil wells completed during
those years effectively reduced future net revenues for this successful efforts
property pool below undepreciated costs. Similarly, the Louisiana Austin Chalk
oil discovery, although successful (see full discussion about this area under
"Recent Activities" in Item 2, Properties), brought into question the likelihood
of future development of certain leaseholds. Where annual renewal rentals either
had already become due or would become due before a reasonable production test
period for the Morrow #23-1H is achieved and/or a new test well promoted,
management chose to write them off as impaired. Also included were numerous
small leaseholds where the possibility of easily putting together a unit was
rather remote. This added charge of $251,000 brought the total non-cash
impairment provision made during the third quarter to $494,000.
Late in the fourth quarter, the Morrow #23-1H did commence production at
rates well below the initial tests so year-end proved reserves attributable to
the horizontal legs were reduced. This resulted in carrying costs in excess of
the fair value and in an impairment charge of $1,140,000 and $84,000 related to
Louisiana leaseholds. Undeveloped leaseholds in general were also impaired in
the amount of $200,000 based upon management's opinion further development may
not be completed prior to some lease expirations. Two oil wells in Oklahoma in
progress at the end of the third quarter failed to respond to attempts to
eliminate shifting frac sands from plugging perforations so an additional
impairment of $260,000 was provided.
The Company elected to adopt early Statement of Financial Accounting
Standards No. 121 ("SFAS-121"), "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" as of the beginning of the
fourth quarter of 1995.
29
<PAGE>
SFAS-121 requires that an impairment loss be recognized when the carrying amount
of an asset exceeds the sum of the undiscounted estimated future cash flow of
the asset. The Company had to provide for impairment of oil and gas properties
based on expected prices and year end proved reserves both of which would be
significantly reduced. Four areas in Texas, Oklahoma, New Mexico and North
Dakota showed that impairment losses were greater than previously anticipated so
it was deemed prudent to elect early adoption. Accordingly, a non-cash loss of
$3,055,000 ($2,260,000 after tax) was recognized as of September 1, 1995.
Prior to September 1, 1995, a valuation provision had only been made if total
capitalized costs of oil and gas properties, excluding unproved properties, by
country, exceeded (1) the present value of future net revenues from estimated
production of proved oil and gas reserves using constant prices discounted at
10% less (2) income tax effects related to differences between book and tax
basis of the properties. Therefore, no impairment had been necessary prior to
adopting SFAS-121 because total capitalized costs in the U.S. were far less than
discounted future net revenues. Interestingly, had Columbus followed the full
cost method no impairments of oil and gas property costs (excluding the
impairment of undeveloped leases) would have been necessary as the total value
of proved reserves of the Company have comfortably exceeded such capitalized
full cost method costs.
Oil and Gas Operations
The following discussion of the Company's oil and gas operations is based
upon the tables of production and average prices shown separately for the United
States and Canada. See Item 2, "Oil and Gas Properties" and "Production".
The changes in the components of oil and gas revenues during the periods
presented are summarized as follows:
Production
Price Change Quantity Change Revenue Change
------------ --------------- --------------
1997 vs. 1996 (All U.S.)
Gas 23 % 25 % 53 %
Oil 1 % 1 % 3 %
1996 vs. 1995
Gas - U.S. 26 % 32 % 64 %
Gas - Canada - % (100)% (100)%
------- -------- --------
Total Company gas 26 % 8 % 44 %
Oil - U.S. 16 % 9 % 28 %
Oil - Canada - % (100)% (100)%
------- -------- --------
Total Company oil 16 % 4 % 23 %
Natural gas revenues increased 53% when compared to 1996 as a result of
higher volumes and prices. Average prices for natural gas increased 23% in 1997
compared with last year due to strong demand and a fairly tight supply of gas
30
<PAGE>
in excess of storage injection requirements. Gas revenues in 1997 were reduced
by $86,400 ($.03 per Mcf) and 1996's revenues were reduced by $518,000 ($.19 per
Mcf) from swaps of natural gas. Sales volumes improved by 25% over 1996 as a
result of numerous gas wells being completed and connected in Texas during the
past year.
Oil revenues for 1997 managed 3% improvement over 1996 as a result of a
sales volume and average price increase of 1% each. Crude oil production
reversed its continuing slide over a several year period as new wells were added
in 1997 which generated the improvement over the prior year's volumes. New oil
and condensate production in Montana and Chambers County, Texas during 1997 was
mostly offset by reductions in Harris County, Texas and North Dakota and by
properties that were sold in late 1996. Oil revenues for 1997 were decreased by
$13,600 ($.06 per barrel) while 1996 revenues were reduced by $256,000 ($1.04
per barrel) from crude oil swaps.
Columbus' 1997 average sales volumes of natural gas of 9,283 Mcfd and oil
and liquids production of 682 barrels per day equates to daily production of
2,229 barrels of oil equivalent (BOE). This surpassed the previous record for
U.S. daily production of 2,200 BOE achieved during the third quarter of 1994 and
the 1997 fourth quarter production averaged 2,354 BOE per day. The next
challenge is to not only maintain but to increase that level of production by
adding substantial new reserves from an expanded exploratory budget hopefully
without expensive failures or high cost successes such as the Morrow #23-1H in
Louisiana.
After the 25% increase in natural gas production during 1997 with an
increase of only 1% in oil production, the Company now produces approximately
70% of its volumes from natural gas. This may be very fortuitous as the price of
crude oil in early 1998 rapidly declined.
Natural gas revenues for 1996 compared to 1995 in the U.S. increased 64%
despite reductions from swaps as a result of a 26% higher price and a 32%
increase in production. Average prices improved because of increased demand and
severely depleted storage levels following an extended 1995/1996 winter heating
season. Natural gas revenues for 1996 were reduced by $518,000 ($.19 per Mcf)
from swaps of natural gas while 1995 had increased revenues of $284,000 ($.14
per Mcf). Production volumes for 1996 increased as a result of property
acquisitions and the effects of newly developed wells.
Oil revenues in the U.S. for 1996 were up 28% from 1995 as a result of a
16% increase in the average price received and 9% higher volumes. Oil revenues
and average prices for 1996 were reduced by $256,000 ($1.04 per barrel) due to
hedging activity. The Company had no oil hedges in 1995. Crude oil production
improved because of two new Jackson sand oil well completions in the Sralla Road
31
<PAGE>
field plus a third discovery (78% WI) gas condensate well almost one mile
southwest which commenced production in November 1996. These increases overcame
normal production declines elsewhere.
Natural gas revenues and production for 1995 decreased compared to 1994
primarily as a result of lower prices, lower gas production in the Sralla Road
field, and a reversionary interest in the Company's most productive gas well in
the Laredo area which accounted for about one-half of the reduced gas
production. These deductions more than offset additional well connections in
Texas and Oklahoma, Average prices for natural gas decreased 11% compared to
1994 but did begin to increase toward the end of fiscal 1995.
Oil revenues for the U.S. for 1995 were up 8% from 1994 as a result of a
10% increase in the average price received. In 1995 low crude oil prices
dictated continued deferral of any revival of an oil development program of
undeveloped oil reserves located in the Williston Basin. However, a moderate
amount of drilling was planned for 1996 as a result of putting the 1996 oil swap
in place which afforded some protection from previous drastic downturns in
prices which each time halted drilling plans before anything could get underway.
U.S. oil prices have fluctuated for several years with the same wide swings
experienced in world crude oil price. In 1995 crude oil prices declined during
mid-year months but recovered by year-end so that the average annual prices were
actually higher than 1994. By the spring of 1996 crude oil prices rose quickly
to above $20 per barrel, declined briefly, then again rose rapidly to almost $23
per barrel by year end. During 1997 crude oil prices have been steadily
softening and have declined each quarter which trend accelerated in the first
quarter of fiscal 1998.
Fluctuations of oil and gas revenues and operations in Canada which appear
in the table are consistent with the spin-off of Resources in February 1995,
i.e. 1996 vs. 1995 revenues decreased 100% which reflects the fact 1995 included
the last quarter of Canadian activity.
Lease operating expenses for 1997 were 6% lower than 1996 despite more
wells in operation because the prior year had several expensive workovers
performed and production equipment was replaced on several older wells. Lease
operating expenses in the U.S. increased 23% in 1996 over 1995's because of
incremental working interest acquisitions and several extensive work-overs
performed in an effort to make some wells more economic. Lease operating costs
on a barrel of oil equivalent basis for 1997 were down to $2.27 compared to
$2.80 in 1996 and $2.78 for 1995. Lease operating expenses in the U.S. increased
19% in 1995 compared to 1994 because of a few expensive work-overs. Lease
operating costs on a barrel of oil equivalent basis for 1995 were up to $2.78
32
<PAGE>
compared to $1.93 for 1994. Operating costs in the U.S. as a percentage of
revenues decreased to 13% in 1997 versus 19% in 1996 due to increasing unit
prices and compared with 22% in 1995.
Production and property taxes approximated 9% of revenues in 1997 and 10%
of revenues in 1996 and 1995. These vary based on Texas' percentage share of the
total production where oil tax rates are lower than gas tax rates. The
relationship of taxes and revenue is not always directly proportional since
several of the local jurisdiction's property taxes are based upon reserve
evaluations as opposed to revenues received or production rates for a given tax
period.
Operating and Management Services
This segment of the Company's U.S. business is comprised of operations and
services conducted on behalf of third parties and includes compressor rentals.
During 1997 operating and management services profit was $349,000 compared
to a $210,000 profit for 1996 as the number of operated wells and drilling
activity increased.
Prior to the Company's divestiture of Resources in 1995, the Company
received significant operating service revenue from its share of processing fees
at the Carbon area liquid extraction plant. Those revenues also included fees
from the processing of Resources' own gas, although no profit was generated from
that portion of revenues since it was offset by a commensurate increase in
Columbus' well operating expenses.
Operating and management services U.S. revenue has increased in each of the
last three years. Until divested in 1995, Canadian operations had contributed
far greater operating margins than the U.S. but U.S. revenues in 1995 improved
because of additional billings for operator services related to 3-D seismic
testing program and past audit adjustments. These factors generated a $199,000
profit for the U.S. segment in that year.
Interest Income
Interest income is earned primarily from short-term investments whose rates
fluctuate with changes in the commercial paper rates and the prime rate.
Interest income increased slightly in 1997 to $147,000 as a result of higher
short-term interest rates achieved and despite a decreased amount of
investments. Interest income decreased in 1996 to $125,000 when compared to
$160,000 in 1995, reflecting a decreased amount of investments and lower
short-term interest rates.
33
<PAGE>
General and Administrative Expenses
General and administrative expenses are considered to be those which relate
to the direct costs of the Company which do not originate from operation of
properties or providing of services. Corporate expense represents a major part
of this category although other nonbillable expenses are included.
The Company's general and administrative expenses in 1997 were much higher
than the prior year due to salary increases in May 1997 for officers and in
November 1996 for employees and to incentive bonuses. The latter were
discretionary and were actually based on the Company's performance in 1996 with
total bonuses of $220,000 ($70,000 non-cash) in 1997 compared to $83,000 (all
non-cash) in 1996. A major source of this increase was also attributable to
legal and accounting expenses which had been accrued in connection with
preparation of a registration statement for a proposed offering of convertible
preferred shares which was withdrawn because of the rapid paydown of debt in
latter 1996 from accelerating cash flow.
During 1997 the Company upgraded its computer software to a new release of
a major software vendor that is compliant with the year 2000 and expensed
$16,000 which is included in general and administrative expenses. The Company
does not expect to incur any other significant amounts in the future in
connection with the year 2000 problem.
The Company's expenses for 1996 were lower than for all of 1995 because of
salary and staff reductions which occurred in August 1995 affected the whole
year. Also, incentive bonuses (all non-cash) totaled only $83,000 in 1996
compared to $110,000 granted in May, 1995.
Reimbursement for services provided by Columbus officers and employees for
managing Resources is expected to decrease in 1998 assuming that Canadian-based
management takes over following an expected business combination that Resources
is currently aggressively seeking. Columbus' general and administrative expense
will rise commensurately when Resources' merger occurs since no staff reductions
are contemplated when this occurs. Reimbursement of $255,000 was realized in
1997 compared to $296,000 in 1996 and $281,000 for all of fiscal year 1995 for
providing services to Resources.
The Company's U.S. only expenses for 1995 were 6% higher than 1994's
because employee salary and staff reductions were offset by higher compensation
from cashless stock option exercises, increased fees associated with a regular
listing on the Amex, shareholder and stock transfer expense, professional
services (which included the fees of a second petroleum engineering firm) and a
higher matching percentage contribution to the Company's 401(k) Plan. Overall,
the total of general and administrative expenses declined in 1995 compared to
1994 due to the spin-off of Resources.
34
<PAGE>
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are
calculated based upon the units of production compared to proved reserves of
each field. The expense is not only directly related to the level of production,
but also is dependent upon past costs to find, develop and recover those
reserves in each of the pools or fields. Depreciation and amortization of office
equipment and computer software is also included in the total charge.
Total charges for depletion expense for oil and gas properties increased in
1997 over 1996 due to increased production and added development expenditures in
the intervening period. Total charges for depletion expense for oil and gas
properties increased in 1996 over 1995 due to greater production despite the
benefit realized from the 1995 write-down of the carrying value of certain
properties upon adoption of SFAS-121. During 1995 depletion expense for oil and
gas properties increased by a greater percentage than the increase in
production. Contributing to the disproportionately higher depletion expense were
much lower gas and crude oil prices during 1995, which tended to reduce
reserves, shorten the estimated reserve life and change the economic limits of
certain of the Company's properties. The lower carrying values of certain oil
and gas properties after the impairment loss with the adoption of SFAS-121
effective September 1, 1995 helped to reduce depletion expense for the fourth
quarter of 1995.
For 1997, the depletion and depreciation rate for the Company was $3.91 per
barrel of oil equivalent ("BOE") compared to $3.86 per BOE for fiscal 1996 and
$3.83 per BOE equivalent in 1995. However, had the benefit of the lower
depletion costs of Canadian gas properties not been included for one quarter,
the higher cost U.S. additions would have raised the 1995 charge to $4.21 per
BOE.
Effective October 1, 1997 the Company sold its interests in seven wells in
the Berry Cox field in Texas for total proceeds of $750,000. These wells were a
part of a larger pool of properties in the Laredo area for purposes of
calculating depletion so those sale proceeds were credited to the costs of the
successful efforts pool and no book gain or loss was recognized. The reduction
in proved reserves connected with the sale could cause a small increase in that
pool's depletion rate in future periods.
Exploration Expense
In general, the exploration expense category includes the cost of
Company-wide efforts to acquire and explore new prospective areas. Until
Resources was divested in February 1995, the Company's exploration expense was
primarily attributable to geological consulting work provided in Canada plus
limited seismic expense in Canada and the U.S. The successful efforts method of
accounting for oil and gas properties requires expensing the costs of
35
<PAGE>
unsuccessful exploratory wells. Other exploratory charges such as 2-D and 3-D
seismic and geological costs must be immediately expensed regardless of whether
a prospect is ultimately proved to be successful.
Exploration charges for 1997 were up dramatically to $540,000 from $318,000
in 1996. These included $224,000 of 3-D seismic costs incurred in the S.E. Froid
area in Montana which located new exploratory well sites, $73,000 incurred for a
non-commercial exploratory oil well along with ongoing exploration efforts.
Subsequent to fiscal year end, a dry exploratory well was drilled in the S.E.
Froid area in Montana so approximately $190,000 will be recorded as an
exploration expense during first quarter 1998.
During 1996 two Oklahoma exploratory wells drilled proved non- economic and
$184,000 was expensed. Most of the balance of the 1996 expense was for
geological consulting. During 1995, seismic survey costs of $46,000 were
incurred in Canada and expensed while undeveloped leasehold costs in North
Dakota were impaired by $69,000 both of which contributed to an exploration
expense of $245,000. All exploration expenses reduce reported GAAP cash flow
from operations even though they are discretionary expenses; however, such
charges are added back for purposes of determining DCF which makes it more
comparable to the cash flow results reported by full cost accounting companies.
Retirement and Separation Expense
During 1995 a total of $32,000 separation expense was paid to employees
whose positions were eliminated and a total of $109,000 was accrued for
retirement compensation for past years' service for two employees who reached
age 65 and were approved by the Board of Directors to receive such compensation.
Litigation Expense
The litigation expenses in 1995 and 1994 related to two lawsuits previously
discussed in detail in prior Annual Reports. The first, Michael Mattalino, Bruce
L. Davis and Maris E. Penn vs. Columbus Energy Corp. filed on April 23, 1993 was
settled by agreement in September 1994. The second, Porter Farrell II vs.
Columbus Energy Corp. filed October 14, 1993 had Columbus' motion for summary
judgment granted on April 12, 1995 and the lawsuit was dismissed.
Interest Expense
Interest expense varies in a direct proportion to the amount of bank debt
and the level of bank interest rates. The average bank interest rate paid for
U.S. debt in 1997, 1996 and 1995 was 7.1%, 7.2%, and 7.9%, respectively.
36
<PAGE>
Income Taxes
The Company's income tax position is somewhat complex. Resources' income was
consolidated with the Company's U.S. income until Columbus' divestiture of
Resources in 1995. Also, the utilization of net operating loss carryforwards by
the Company has been complicated by two "change of ownership" transactions under
Section 382 of the Internal Revenue Code, one of which occurred on October 1,
1987 and the other on August 25, 1993. Only the first of those changes has
limited the utilization of net operating loss carryforwards. Furthermore, a
quasi-reorganization occurred on December 1, 1987 which requires that benefits
from net operating loss carryforwards or any other tax credits that arose prior
to the quasi-reorganization be credited to additional paid-in capital rather
than to income. Only post quasi-reorganization tax benefits realized can be
credited to income.
As a result of available net operating loss carryforwards, the Company's
Federal income tax obligations have been limited to "alternative minimum tax" so
that the Company has had a current Federal tax payable of less than 2% of
pre-tax earnings. In 1997, the Company has a net operating loss carryforward
from 1995 and operating loss carryforwards remaining from periods prior to the
first Section 382 ownership change. Utilization of those latter benefits are
limited to $904,000 per year so that the Company's current Federal tax provision
and liability may increase in 1998 and thereafter unless an active drilling
program is maintained. In addition, the Company pays state income taxes and
previously, until its divestiture, also included Canadian taxes on Resources'
income.
During 1995, the U.S. net deferred tax asset was reduced to $638,000 which is
comprised of a $1,290,000 current deferred tax asset and a $652,000 long-term
tax liability. The deferred tax asset increased by an estimated $537,000 during
1995. The valuation allowance was increased by a net $96,000 even after Canadian
deferred taxes were reduced by $233,000 since such a provision was no longer
required following the divestiture. The estimated effective tax rate for 1995
was a 26% book benefit.
During 1996, the net deferred tax asset was reduced to $1,000 which is
comprised of $631,000 current deferred tax asset and $630,000 long-term
liability. The valuation allowance had a net reduction of $268,000 from 1995 to
November 30, 1996. A deduction of $102,000 for the benefit of disqualifying
disposition of incentive stock options was added to additional paid-in capital.
During 1997, there was a net deferred tax liability of $989,000 which is
comprised of $201,000 current portion and $788,000 long-term liability. The
valuation allowance had a net reduction of $26,000 from 1996 to November 30,
1997. A deduction of $76,000 for the benefit of disqualifying disposition of
incentive stock options was added to additional paid-in capital.
37
<PAGE>
Effects of Changing Prices
The United States economy experienced considerable inflation during the late
1970's and early 1980's but in recent years has been fairly stable and at low
levels. The Company, along with most other U.S. business enterprises, was then
and would be affected by any recurrence of such economic conditions. Inflation
in general has had a minimal effect on the Company.
In recent years, oil and natural gas prices have fluctuated widely so the
Company's results of operations and cash flow have been directly affected. Oil
and gas prices have also been significantly influenced by regulation by various
governmental agencies, by the world economy, and by world politics. Operating
expenses have been relatively stable but, when analyzed as a percentage of
revenues, may be distorted because they become a larger percentage of revenues
when lower product prices prevail. Drilling and equipment costs have risen
noticeably in the last two years. Competition in the industry can significantly
affect the cost of acquiring leases, although in the past decade competition has
lessened as more operators have withdrawn from active exploration programs.
Inflation, as well as a recessionary period, can cause significant swings in the
interest rates the Company pays on bank borrowings. These factors are
anticipated to continue to affect the Company's operations, both positively and
negatively, for the foreseeable future.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The report of independent accountants and consolidated financial statements
listed in the accompanying index are filed as part of this report. See Index to
Consolidated Financial Statements on page 42.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
38
<PAGE>
PART III
Items 10 and 11. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
AND EXECUTIVE COMPENSATION
A definitive proxy statement related to the 1998 Annual Meeting of
Stockholders of Columbus Energy Corp. will be filed no later than 120 days after
the end of the fiscal year with the Securities and Exchange Commission. The
information set forth therein under "Nominees for Election of Directors,"
"Executive Officers of the Company," and "Executive Compensation" is
incorporated herein by reference.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Information required is set forth under the caption "Voting Securities and
Principal Holders Thereof" in the Proxy Statement for the 1998 Annual Meeting of
Stockholders and is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required is set forth under the caption "Election of Directors"
in the Proxy Statement for the 1998 Annual Meeting of Stockholders and is
incorporated herein by reference.
39
<PAGE>
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K
Page
(a) Financial statements and schedules ----
included in this report:
See "Index to Consolidated Financial Statements" 42
All schedules are omitted since either the required information is set
forth in the financial statements or in the notes thereto or the
information called for is not present in the accounts or is not required
under the exception stated in Rule 5.04.
(b) Reports on Form 8-K:
The following reports on Form 8-K were filed on behalf of the Registrant
since the third quarter of fiscal 1997:
None
(c) Exhibits:
Exhibit No.
- -----------
* 3(a) Restated Articles of Incorporation and Amendments thereto to date
(Exhibit to Registration Statement No. 33-17885, Exhibit "a" to Form
10-Q dated July 13, 1990 and Exhibit 3(1)(a) to Form 8-K dated May 11,
1995).
* 3(b) Amended By-Laws of Columbus Energy Corp. amended as of October
18, 1994 (Exhibit to Form 8-K dated October 20, 1994) and as of
February 13, 1995 (Exhibit to Form 8-K dated February 16, 1995).
* 10(a) Amended and Restated Credit Agreement dated as of October 23,
1996 between Columbus Energy Corp. and Norwest Bank Denver, National
Association (Exhibit 10(a) to Registration Statement No. 333-19643
dated January 13, 1997).
* 10(b) 1993 Stock Purchase Plan (Exhibit to Registration Statement No.
33-63336).
* 10(c) 1995 Stock Option Plan (Exhibit 10 (k) to Form 8-K dated May 11,
1995).
* 10(d) 1985 Stock Option Plan (Exhibit to Registration Statement No.
33-17885).
* 10(e) 1985 Stock Option Plan, Amendment No. 2 dated November 7, 1991
(Exhibit 10(h) to Form 10-K dated November 30, 1991).
40
<PAGE>
* 10(f) Separation Pay Policy adopted December 1, 1990 for officers and
employees and as amended February 17, 1992 (Exhibit 10(i) to Form 10-K
dated November 30, 1991).
* 10(g) Form of Indemnity Agreements with directors (Exhibit 10(k) to
Registration Statement No. 33-46394).
11 Statement of computation of per share earnings.
22 Subsidiaries of the Registrant.
23(a) Consent of Coopers & Lybrand L.L.P.
23(b) Consent of Reed W. Ferrill & Associates, Inc.
23(c) Consent of Huddleston & Co., Inc.
27 Financial Data Schedule
- ---------------
*Incorporated by reference
41
<PAGE>
COLUMBUS ENERGY CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants 43
Financial Statements:
Consolidated Balance Sheets at
November 30, 1997 and 1996 44
Consolidated Statements of Operations for the
years ended November 30, 1997, 1996 and 1995 46
Consolidated Statements of Stockholders'
Equity for the years ended
November 30, 1997, 1996 and 1995 48
Consolidated Statements of Cash Flows for the
years ended November 30, 1997, 1996 and 1995 50
Notes to the Consolidated Financial Statements 51
42
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
Columbus Energy Corp.
We have audited the accompanying consolidated balance sheets of Columbus
Energy Corp. and subsidiaries as of November 30, 1997 and 1996, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended November 30, 1997. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
consolidated financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Columbus Energy Corp. and subsidiaries as of November 30, 1997 and 1996, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended November 30, 1997, in conformity with generally
accepted accounting principles.
As explained in Note 2 to the consolidated financial statements, effective
September 1, 1995, the Company changed its method of accounting for the
impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Denver, Colorado
February 11, 1998
43
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
November 30,
-------------------------
1997 1996
---- ----
(in thousands)
Current assets:
Cash and cash equivalents $ 1,857 $ 1,396
Accounts receivable:
Joint interest partners 1,932 889
Oil and gas sales 2,054 1,544
Allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 5) - 631
Inventory of oil field equipment,
at lower of average cost or market 102 115
Other 82 77
------- -------
Total current assets 5,911 4,536
------- -------
Property and equipment:
Oil and gas assets, successful
efforts method (Notes 3 and 4) 33,803 28,031
Other property and equipment 2,053 2,001
------- -------
35,856 30,032
Less: Accumulated depreciation,
depletion, amortization and
valuation allowance
(Notes 2 and 3) (15,632) (12,943)
-------- -------
Net property and equipment 20,224 17,089
-------- -------
$ 26,135 $21,625
======== =======
(continued)
44
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
November 30,
-------------------
1997 1996
---- ----
(in thousands)
Current liabilities:
Accounts payable $ 3,023 $ 1,292
Undistributed oil and gas
production receipts 393 54
Accrued production and property taxes 551 555
Prepayments from joint interest owners 565 258
Accrued expenses 377 348
Income taxes payable (Note 5) 42 33
Deferred income taxes (Note 5) 201 -
Other 37 30
------- ------
Total current liabilities 5,189 2,570
------- ------
Long-term bank debt (Note 4) 2,200 2,200
Deferred income taxes (Note 5) 788 630
Commitments and contingent liabilities (Note 8)
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; 4,492,068 shares
issued in 1997 and 3,499,915 in 1996
(outstanding 3,883,557 in 1997 and
3,155,346 in 1996) (Notes 1 and 7) 898 700
Additional paid-in capital 18,124 17,361
Retained earnings 2,887 720
------- -------
21,909 18,781
Less:
Treasury stock, at cost (Note 7)
608,511 shares in 1997 and
344,569 shares in 1996 (3,951) (2,556)
------- -------
Total stockholders' equity 17,958 16,225
------- -------
$26,135 $21,625
======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
45
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended November 30,
-----------------------------------
1997 1996 1995
---- ---- ----
(in thousands, except per share data)
Revenues:
Oil and gas sales $13,815 $10,572 $ 7,902
Operating and management
services 1,176 1,087 1,338
Gain (loss) on sale of asset (60) 31 -
Interest income and other 165 125 160
------- ------- -------
Total revenues 15,096 11,815 9,400
------- ------- -------
Costs and expenses:
Lease operating expenses 1,849 1,965 1,811
Property and production taxes 1,258 1,051 780
Operating and management
services 827 877 1,017
General and administrative 1,372 999 1,278
Depreciation, depletion and
amortization 3,295 2,835 2,757
Impairments 2,179 165 3,055
Exploration expense 540 318 245
Retirement and separation - - 141
Litigation expense 10 16 127
------- ------- -------
Total costs and expenses 11,330 8,226 11,211
------- ------- -------
Operating income (loss) 3,766 3,589 (1,811)
------- ------- -------
Other (income) expense:
Interest 174 260 185
Other (4) 2 26
------- ------- -------
170 262 211
------- ------- -------
Earnings (loss) before
income taxes 3,596 3,327 (2,022)
Provision (benefit) for income
taxes (Note 5) 1,429 1,229 (527)
------- ------- -------
Net earnings (loss) $ 2,167 $ 2,098 $(1,495)
======= ======= =======
(continued)
46
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS - (continued)
Year Ended November 30,
-----------------------------------
1997 1996 1995
---- ---- ----
(in thousands, except per share data)
Earnings (loss) per share:
Primary $ .55 $ .54 $ (.38)
======= ======= =======
Fully diluted N/A $ .51 N/A
=======
Average number of common and
common equivalent shares
outstanding:
Primary 3,908 3,872 3,928
======= ======= =======
Fully diluted N/A 4,086 N/A
=======
The accompanying notes are an integral part of these consolidated financial
statements.
47
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For The Three Years Ended November 30, 1997
<TABLE>
<CAPTION>
Cumulative
Retained Foreign
Common Stock Additional Earnings Currency Treasury Stock
----------------------- Paid-In (Accumulated Translation ------------------
Shares Amount Capital Deficit) Adjustments Shares Amount
------ ------ ---------- ------------ ----------- ------ ------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1994 3,282,109 $ 656 $ 15,855 $ 2,814 $ (496) 334,597 $ (2,627)
Exercise of employee
stock options 35,658 8 158 - - - -
Adjustment for
foreign currency
translation, net of
$326,000 income tax - - - - 496 - -
Tax benefit of
disqualifying
disposition of
incentive stock
options - - 25 - - - -
Purchase of shares - - - - - 246,631 (1,860)
Shares issued for Stock
Purchase Plan 10,813 2 85 - - (2,719) 22
Dividend related to
Resources rights
offering (Note 1) - - - (582) - - -
10% stock dividend - - (202) (2,115) - (291,399) 2,314
Shares issued for
Incentive Bonus Plan,
directors' fees
and retirement - - (79) - - (26,679) 207
Net loss - - - (1,495) - - -
---------- ------- -------- ------- ---- -------- -------
Balances,
November 30, 1995 3,328,580 666 15,842 (1,378) -0- 260,431 (1,944)
Exercise of employee
stock options 161,433 32 948 - - 43,800 (370)
Tax benefit of
disqualifying
disposition of
incentive stock
options - - 102 - - - -
Purchase of shares - - - - - 86,100 (579)
Shares issued for oil and
gas properties - - 31 - - (30,000) 223
Shares issued for Stock
Purchase Plan 9,902 2 51 - - (2,492) 18
Shares issued for
Incentive Bonus Plan and
directors' fees - - (22) - - (13,270) 96
Income tax benefit of
loss carryforwards
arising prior to
quasi-reorganization - - 409 - - - -
Net earnings - - - 2,098 - - -
---------- ------- -------- ------- ---- -------- -------
Balances,
November 30, 1996 3,499,915 700 17,361 720 -0- 344,569 (2,556)
---------- ------- -------- ------- ---- -------- -------
(continued)
</TABLE>
48
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For The Three Years Ended November 30, 1997
<TABLE>
<CAPTION>
Cumulative
Retained Foreign
Common Stock Additional Earnings Currency Treasury Stock
----------------------- Paid-In (Accumulated Translation ------------------
Shares Amount Capital Deficit) Adjustments Shares Amount
------ ------ ---------- ------------ ----------- ------ ------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Exercise of employee
stock options 99,233 $ 20 $ 548 $ - $ - 13,333 $ (131)
Purchase of shares - - - - - 158,014 (1,381)
Shares issued for Stock
Purchase Plan 6,996 1 62 - - (1,762) 12
Shares issued for
Incentive Bonus Plan
and directors' fees - - (7) - - (13,451) 105
Shares issued under
five-for-four stock
split 885,924 177 (178) - - 107,808 -
Tax benefit of disqualifying
disposition of incentive
stock options - - 76 - - - -
Income tax benefit of
loss carryforwards
arising prior to
quasi-reorganization - - 262 - - - -
Net earnings - - - 2,167 - - -
---------- ------- -------- ------- ---- -------- -------
Balances,
November 30, 1997 4,492,068 $ 898 $18,124 $ 2,887 $ -0- 608,511 $(3,951)
========== ======= ======== ====== ==== ======== =======
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
49
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended November 30,
----------------------------------
1997 1996 1995
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Net earnings (loss) $ 2,167 $ 2,098 $(1,495)
Adjustments to reconcile net earnings (loss) to
net cash provided by operating activities:
Depreciation, depletion, and
amortization 3,295 2,835 2,757
Impairments and loss on asset dispositions 2,179 165 3,055
Deferred income tax provision 1,328 1,148 (576)
Exploration expense, noncash portion - - 69
Other 163 94 110
Changes in operating assets and liabilities:
Accounts receivable (1,554) (358) 411
Other current assets 21 (38) 40
Accounts payable 352 (22) 147
Undistributed oil and gas production receipts 339 (294) (89)
Accrued production and property taxes (4) (80) (35)
Prepayments from joint interest owners 307 69 (264)
Income taxes payable (receivable) 9 41 (32)
Other current liabilities 36 (20) (169)
------- ------- -------
Net cash provided by operating activities 8,638 5,638 3,929
------- ------- -------
Cash flows from investing activities:
Proceeds from sale of assets 1,005 606 34
Proceeds from sale of Resources
common stock, net of cash - - 4,075
Additions to oil and gas properties (8,172) (6,863) (4,144)
Additions to other assets (127) (63) (84)
------- ------ -------
Net cash used in investing activities (7,294) (6,320) (119)
------- ------ -------
Cash flows from financing activities:
Proceeds from long-term debt 3,000 3,400 2,090
Reduction in long-term debt (3,000) (2,800) (4,690)
Proceeds from exercise of stock options 498 643 209
Purchase of treasury stock (1,381) (579) (1,830)
Other - - (2)
------- ------ -------
Net cash provided by (used in)
financing activities (883) 664 (4,223)
------- ------- -------
Effect of exchange rate on cash - - 8
------- ------- -------
Net decrease in cash and cash equivalents 461 (18) (405)
Cash and cash equivalents at beginning of year 1,396 1,414 1,819
------- ------ -------
Cash and cash equivalents at end of year $ 1,857 $ 1,396 $ 1,414
======= ======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 182 $ 250 $ 214
======= ======= =======
Income taxes (net of refunds) $ 91 $ 41 $ 82
======= ======= =======
Supplemental disclosure of non-cash investing and financing activities:
Non-cash compensation expense
related to common stock $ 98 $ 114 $ 162
======= ======= =======
Oil and gas property additions $ - $ 253 $ 185
======= ======= =======
Use of loss carryforwards credited to
additional paid-in-capital $ 262 $ 409 $ -
======= ======= =======
Dividend for Resources rights $ - $ - $ 582
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
50
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(1) FORMATION AND OPERATIONS OF THE COMPANY
Columbus Energy Corp. ("Columbus") was incorporated as a Colorado
corporation on October 7, 1982 primarily to explore for, develop, acquire and
produce oil and gas reserves. Columbus' wholly-owned subsidiary is Columbus Gas
Services, Inc. ("CGSI"). CEC Resources Ltd. ("Resources") was also a
wholly-owned subsidiary prior to February 24, 1995 when it was divested by
Columbus by a rights offering to its shareholders (see below). Columbus and its
subsidiary are referred to in these Notes to the Financial Statements as the
"Company".
On February 24, 1995, Columbus completed a rights offering to the Columbus
shareholders to purchase one share of Resources at U.S.$3.25 cash plus two
subscription rights. One right was distributed as a dividend for each share held
of record on January 27, 1995. All 1,500,000 shares of Resources common stock
were subscribed (and oversubscribed) and yielded an aggregate of $4,875,000
before deduction of Resources' cash of $674,000 and $126,000 for the costs of
the offering. At the date of divestiture Resources' book assets totaled
$5,434,000 and liabilities were $977,000 with $874,000 cumulative foreign
currency loss in equity. The total value assigned to the rights on its books was
$582,000 for the dividend portion of the purchase of Resources shares. No gain
or loss can be recognized for book purposes in a spin-off. The combination of
the cash offering price of $3.25 per share plus the value of the rights dividend
assigned was equal to the U.S. historical book cost of Columbus' investment in
Resources. The divestiture was the sale of a foreign subsidiary engaged in the
same business as Columbus. No taxes were due Revenue Canada as a result of this
divestiture of common stock because the tax basis exceeded the proceeds received
upon disposition.
(2) ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared in
accordance with generally accepted accounting principles and require the use of
managements' estimates. The following is a summary of the significant accounting
policies followed by the Company.
Consolidation
-------------
The accompanying consolidated financial statements include the accounts of
Columbus and its wholly-owned subsidiaries, CGSI and Resources through February
24, 1995. All significant intercompany balances have been eliminated in
consolidation.
51
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Cash Equivalents
----------------
For purposes of the statement of cash flows, the Company considers all
highly liquid debt instruments purchased with a maturity of three months or less
to be cash equivalents. Hedging activities are included in cash flow from
operations in the cash flow statements.
Financial Instruments and Concentrations of Credit Risk
-------------------------------------------------------
The Company maintains demand deposit accounts with separate banks in
Denver, Colorado. The Company also invests cash in the highest rated commercial
paper of large U.S. companies, with maturities not over 30 days, which have
minimal risk of loss. At November 30, 1997 and 1996 the Company had investments
in commercial paper of $900,000 and $1,000,000, respectively. The carrying
amount of long-term debt approximates fair value because the interest rate on
this instrument changes with market interest rates.
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of cash and cash equivalents
and accounts receivable. Columbus as operator of jointly owned oil and gas
properties, sells oil and gas production to relatively large U.S. oil and gas
purchasers (see Note 3), and pays vendors for oil and gas services. The risk of
non-payment by the purchasers, counter parties to the crude oil and natural gas
swap agreements or joint owners is considered minimal. The Company does not
obtain collateral from its oil and gas purchasers for sales to them. Joint
interest receivables are subject to collection under the terms of operating
agreements which provide lien rights to the operator.
Oil and Gas Properties
----------------------
The Company follows the successful efforts method of accounting. Lease
acquisition and development costs (tangible and intangible) for expenditures
relating to proved oil and gas properties are capitalized. Delay and surface
rentals are charged to expense in the year incurred. Dry hole costs incurred on
exploratory operations are expensed. Dry hole costs associated with developing
proved fields are capitalized. Expenditures for additions, betterments, and
renewals are capitalized. Exploratory geological and geophysical costs are
expensed when incurred.
Upon sale or retirement of proved properties, the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and any gain
or loss is credited or charged to income if significant. Abandonment,
52
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
restoration, dismantlement costs and salvage value are taken into account in
determining depletion rates. These costs are generally about equal to the
proceeds from equipment salvage upon abandonment of such properties. When
estimated abandonment costs exceed the salvage value, the excess cost is accrued
and expensed. Maintenance and repairs are charged to operating expenses.
Provision for depreciation and depletion of capitalized exploration and
development costs are computed on the unit-of-production method based on proved
developed reserves of oil and gas, as estimated by petroleum engineers, on a
property by property basis. Prior to September 1, 1995, an additional valuation
provision was made if total capitalized costs of oil and gas properties,
excluding unproved properties, by country exceeded (1) the present value of
future net revenues from estimated production of proved oil and gas reserves
using constant prices discounted at 10% less (2) income tax effects related to
differences between book and tax basis of the properties. Unproved properties
are assessed periodically to determine whether they are impaired. When
impairment occurs, a loss is recognized by providing a valuation allowance. When
leases for unproved properties expire, any remaining cost is expensed.
Effective for the fourth quarter beginning September 1, 1995 the Company
adopted Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("SFAS-121"). This statement prescribes the accounting for the impairment of
long-lived assets, such as oil and gas properties. An impairment loss is
reported as a component of income from continuing operations. The Company
recognizes an impairment loss when the carrying value exceeds the expected
undiscounted future net cash flows of each property pool at which time the
property pool is written down to the fair value. Fair value is estimated to be a
discounted present value of expected future net cash flows with appropriate risk
consideration.
53
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company uses crude oil and natural gas hedges to manage price exposure.
Realized gains and losses on the hedges are recognized in oil and gas sales as
settlement occurs.
The Company follows the entitlements method of accounting for gas balancing
of gas production. The Company's gas imbalances are immaterial at November 30,
1997 and 1996.
Other Property and Equipment
----------------------------
Other property and equipment consists of office and computer equipment.
Gains and losses from retirement or replacement of other properties and
equipment are included in income. Betterments and renewals are capitalized.
Maintenance and repairs are charged to operating expenses. Depreciation of other
assets are provided on the straight line method over their estimated useful
lives.
Income Taxes
------------
The Company files a consolidated income tax return with CGSI. Resources,
its Canadian subsidiary, was also included in the consolidated U.S. income tax
return through February 24, 1995 before terminating with completion of the
divestiture. Resources was also subject to tax under applicable Canadian tax
law. Columbus and its consolidated subsidiary have executed a tax allocation
agreement which provides for an allocation and payment of U.S. income taxes
based upon each Company's separate tax liability calculation.
Operating and Management Services
---------------------------------
The Company recognizes revenue for operating and management services
provided to other companies and non-operating interest owners in which the
Company has no economic interest. The Company receives overhead fees, management
fees and revenues related to gas marketing, compression and gathering.
The cost of providing such services is expensed and shown as "operating and
management services" cost.
Earnings Per Share
------------------
Earnings per share is computed using the weighted average number of common
shares outstanding. Stock options are included as common stock equivalents, when
dilutive, using the treasury stock method. For 1996 common stock equivalents
include shares issuable upon assumed exercise of dilutive stock options using
the average price for primary shares and the much higher year end price for
54
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
fully diluted shares. For 1995 and 1997 such common stock equivalents were not
dilutive. Historical amounts have been adjusted for the 10% stock dividend
distribution in 1995 and the five-for-four stock split in 1997.
In March 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 128, "Earnings Per Share," effective
for interim and annual periods ending after December 15, 1997. SFAS No. 128
replaces the calculation of Primary Earnings per Share with a calculation called
Basic Earnings per Share and replaces Fully Diluted Earnings per Share with a
calculation called Diluted Earnings per Share. The following table shows the
impact that adoption of SFAS No. 128, as of December 1, 1994, would have had on
the Company's reported earnings per share.
For the year ended November 30,
-------------------------------
1997 1996 1995
---- ---- ----
Primary earnings (loss) per
share (as reported) $0.55 $0.54 $(0.38)
Basic earnings (loss) per
share (proforma) 0.55 0.55 (0.38)
Fully diluted earnings (loss)
per share (as reported) N/A 0.51 N/A
Diluted earnings (loss) per
share (proforma) 0.54 0.54 (0.38)
Accounting for Stock-Based Compensation
- ---------------------------------------
The Financial Accounting Standards Board issued Statement No. 123 on the
"Accounting for Stock-Based Compensation". This statement prescribes the
accounting and reporting standards for stock-based employee compensation plans
and is effective for the Company's 1997 fiscal year. The Company is using the
alternative pro forma disclosures as provided.
New Accounting Pronouncement
- ----------------------------
The Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income," was issued in June 1997 and establishes standards for
reporting and display of comprehensive income and its components (revenues,
expenses, gains, and losses) in a full set of general-purpose financial
statements. This statement is effective for financial statements for periods
beginning after December 15, 1997 and adoption of the statement is not
anticipated to have a material impact on the Company's financial position and
results of operations.
55
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(3) OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth the capitalized costs related to U.S. oil
and gas producing activities, costs incurred in oil and gas property
acquisition, exploration and development activities, and results of operations
for producing activities:
Capitalized Costs Relating to Oil and Gas
Producing Activities
(in thousands)
November 30,
----------------------
1997 1996
------- -------
Proved properties $33,074 $27,156
Unproved properties 729 875
------- -------
33,803 28,031
Less accumulated depreciation,
depletion, amortization and
valuation allowance (14,175) (11,519)
------- -------
Total net properties $19,628 $16,512
======= =======
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES
(in thousands)
Year Ended November 30,
----------------------------------------------
1997 1996 1995
------ ------ -----------------------
United United United
States States Total States Canada
Property acquisition
costs:
Proved $ - $3,025 $1,443 $1,443 $ -
Unproved 508 976 85 85 -
Exploration costs 540 318 245 196 49
Development costs 9,043 3,115 2,843 2,771 72
------ ------ ------ ------ ------
Total costs incurred $10,091 $7,434 $4,616 $4,495 $ 121
======= ====== ====== ====== ======
56
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
(in thousands)
Year Ended November 30,
----------------------------------------------
1997 1996 1995
------ ------ -----------------------
United United United
States States Total States Canada
------ ------ ----- ------ ------
Sales $13,815 $10,572 $7,902 $7,269 $ 633
Production (lifting)
costs (a) 3,107 3,016 2,591 2,343 248
Exploration expenses 540 318 245 196 49
Impairment of long-
lived assets 2,179 165 3,055 3,055 -
Depreciation
depletion and
amortization (b) 3,194 2,703 2,543 2,410 133
------- ------- ------ ------ ------
4,795 4,370 (532) (735) 203
Imputed income tax 1,905 1,614 (138) (209) 71
------- ------- ------ ------ ------
Results of operations
from producing
activities
(excluding overhead
and interest
incurred) $ 2,890 $ 2,756 $ (394) $ (526) $ 132
======= ======= ====== ====== ======
(a) Production costs include lease operating expenses, production and property
taxes
(b) Amortization expense per equivalent barrel of production: 1997 - $3.91 1996
- $3.86 1995 - $3.83
For the years ended November 30, 1997, 1996 and 1995, the Company had the
following customers who purchased production equal to more than 10% of its total
revenues. The following table shows the amounts purchased by each customer.
1997 1996 1995
------------------ ------------------ ------------------
Amount % Revenue Amount % Revenue Amount % Revenue
------ --------- ------ --------- ------ ---------
Customer A $2,956 21.4% $3,142 29.7% $ 2,027 29.7%
Customer B 6,536 47.3 5,513 52.2 2,635 36.2
Customer C 1,395 10.1 1,212 11.5 1,046 14.4
In the Company's judgment, termination by any purchaser under which its
present sales are made would not have a material impact upon its ability to sell
its production to another purchaser at similar prices.
57
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(4) LONG-TERM DEBT
The Company has a Credit Agreement ("Agreement") with Norwest Bank Denver,
N.A. ("Bank") having a borrowing base of $10,000,000, which is subject to
semi-annual redetermination for any increase or decrease. On October 23, 1996
the Credit Agreement was amended and restated to extend the revolving period and
maturity date. The loan revolves until July 1, 1999 and then in its entirety
converts to an amortizing term loan which matures July 1, 2003. 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 1/2%. In addition, a
commitment fee of 1/4 of 1% of the average unused portion of the credit is
payable quarterly.
At November 30, 1997 outstanding borrowings on the revolving line of credit
were $2,200,000 and the unused borrowing base available was $7,800,000. The
$2,200,000 bears interest at LIBOR rate of 5.68% plus 1 1/2%.
The Agreement as amended provides that certain financial covenants be met
which include a minimum net worth of $8,300,000 plus 50% of Cumulative Net
Income after November 30, 1991, a quarterly calculation of a current ratio of
not less than 1.0:1.0 and a ratio of Funded Debt to Consolidated Net Worth not
greater than 1.25:1.00. Columbus has complied with these covenants. Under the
terms of the Agreement, Columbus is permitted to declare and pay a dividend in
cash so long as no default has occurred or a mandatory prepayment of principal
is pending.
The scheduled payments of long-term debt are as follows (in thousands):
Year ending November 30,:
1998 $ -
1999 183
2000 550
2001 550
2002 and after 917
-------
Total $ 2,200
58
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(5) INCOME TAXES
The provision (benefit) for income taxes consists of the following (in
thousands):
1997 1996 1995
---- ---- ----
Current:
Federal $ 13 $ 2 $ -
Foreign (Canada) - - 29
State 88 79 20
------ ------ ----
101 81 49
------ ------ ----
Deferred:
Federal 942 288 (612)
Use of loss carryforwards 347 848 -
Foreign (Canada) - - 44
State 39 12 (8)
------ ------ -----
1,328 1,148 (576)
------ ------ -----
Total income tax
(benefit) expense $ 1,429 $1,229 $(527)
======= ====== =====
The components of earnings (loss) before income taxes are (in thousands):
1997 1996 1995
---- ---- ----
U.S. $ 3,596 $ 3,327 $(2,231)
Canada - - 209
------ ------ -------
Total $ 3,596 $ 3,327 $(2,022)
======= ======= =======
Total tax provision has resulted in effective tax rates which differ from
the statutory Federal income tax rates. The reasons for these differences are:
Percent of Pretax Earnings
----------------------------
1997 1996 1995
---- ---- ----
U.S. Statutory rate 34 % 34 % (34)%
Foreign taxes (Canada) - - 4
State income taxes 2 6 (4)
Change to post-1987
carryforwards 2 4 13
Percentage depletion - (7) (5)
Foreign tax credit/deduction - - (4)
Other 2 - 4
--- --- ---
Effective rate 40 % 37 % (26)%
=== === ===
59
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company files a consolidated income tax return with its subsidiary and
has executed a tax allocation agreement which provides for an allocation and
payment of U.S. income taxes based upon each company's separate tax liability
calculation.
The net operating loss carryforwards and percentage depletion deductions
are for U.S. tax purposes only. For Canadian income tax purposes, when the
annual taxable income of Resources exceeded its available Canadian tax
allowances and deductions for that year, current income taxes were provided and
a tax liability recorded. Canadian taxes were currently payable in 1995.
Consolidated U.S. income taxes are payable only when taxable income exceeds
available U.S. net operating loss carryforwards and other credits.
Pursuant to provisions enacted as part of the Tax Reform Act of 1986,
utilization of these corporate tax carryforwards in any one taxable year is
limited if a corporation experiences a 50% change of ownership. Columbus
experienced such a change of ownership in October, 1987 effectively limiting the
utilization of pre-change ownership net operating losses to approximately
$900,000 in each subsequent year. Subsequent additional ownership changes
accumulated to more than 50% by August 25, 1993 thereby causing a second
ownership change to occur. The remaining post-1987 net operating loss
carryforwards were fully utilized during fiscal 1996.
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" (SFAS-109) requires the asset and liability approach be used to account
for income taxes. Under this method, deferred tax liabilities and assets are
determined based on the temporary differences between financial statement and
tax basis of assets and liabilities using enacted rates in effect for the year
in which the differences are expected to reverse. U.S. tax assets (net of a
valuation allowance) primarily result from net operating loss carryforwards,
percentage depletion and certain accrued but unpaid employee benefits. U.S.
deferred tax liabilities result from the recognition of depreciation, depletion
and amortization in different periods for financial reporting and tax purposes.
Because of the Company's previous 1987 quasi-organization, SFAS-109
requires the Company to report the effect of its net deferred tax asset arising
prior to December 1, 1987 as an increase in stockholders' equity rather than as
an increase to net earnings.
60
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
During fiscal 1997, certain U.S. tax assets (shown in the table below) were
utilized and the valuation allowance was decreased during the year by $26,000.
The tax effect of significant temporary differences representing U.S.
deferred tax assets and liabilities and changes were as follows (in thousands):
<TABLE>
<CAPTION>
Current Year
---------------------------
Dec. 1, Stockholders' Nov. 30,
1996 Equity Operations 1997
------- ------------- ---------- --------
<S> <C> <C> <C> <C>
Deferred tax assets:
Pre-1987 loss carryforwards $1,361 $ - $ (308) $1,053
Post-1987 loss carryforwards 596 - (56) 540
Percentage depletion
carryforwards 1,130 - 174 1,304
State income tax loss
carryforwards 88 - 17 105
Other 308 - 19 327
------ ----- ----- ------
Total 3,483 - (154) 3,329
Valuation allowance (long-term) (1,469) 262(a) (236) (1,443)
------ ----- ----- ------
Deferred tax assets 2,014 262 (390) 1,886
------ ----- ----- ------
Tax benefit of disqualifying
disposition of incentive
stock options - 76(a) (76) -
------ ----- ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (2,013) - (862) (2,875)
------ ----- ------ ------
Net tax asset (liability) $ 1 $ 338 $(1,328) $ (989)
====== ===== ======= ======
</TABLE>
- ------------------------
(a) Credited to additional paid-in capital.
The Company has approximate net operating loss carryforwards (in thousands)
available at November 30, 1997 as follows:
Net
Expiration Year Operating loss
--------------- --------------
1999 $1,808
2000 903
2001 387
2010 1,589
-------
$ 4,687
=======
61
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
For U.S. Alternative Minimum Tax purposes the Company had net operating
loss carryforwards of approximately $5,848,000 as of November 30, 1997. The
Company also has percentage depletion carryforwards of $2,908,000 which do not
expire. State income tax operating loss carryforwards of approximately
$1,730,000 are available at November 30, 1997.
The earnings before income taxes for financial statements differed from
taxable income as follows (in thousands):
1997 1996 1995
---- ---- ----
Earnings (loss) before income taxes
per financial statements $ 3,596 $ 3,327 $(2,022)
Differences between income
before taxes for financial
statement purposes and
taxable income:
Intangible drilling costs
deductible for taxes (6,158) (1,520) (3,125)
Excess of book over tax
depletion, depreciation
and amortization 1,683 754 607
Disqualifying disposition of
incentive stock options (200) (273) (88)
Impairment expense 1,843 165 3,055
Lease abandonments (13) (117) (258)
Dividend of rights of Resources - - 234
Other 153 (95) 72
------- ------- ------
Federal taxable income $ 904 $ 2,241 $(1,525)
======= ======= =======
Realization of the future tax benefits is dependent on the Company's
ability to generate taxable income within the carryfor ward period. Based upon
the proved reserves as of November 30, 1997 as well as contemplated drilling
activities, but excluding revenues from any possible future increase in proved
reserves, management believes that taxable income during the carryforward period
will be sufficient to partially utilize the NOL's before they expire. Of the
total valuation allowance of $1,443,000 as of November 30, 1997, $736,000
relates to pre-quasi-reorganization tax assets and the balance of $707,000
relates to post-quasi- reorganization tax assets. In future periods, reduction
of the pre-quasi-reorganization portion of the valuation allowance will be
credited to additional paid-in capital and reduction of the post-
quasi-reorganization portion of the valuation allowance will be credited to
income.
62
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Estimates of future taxable income are subject to continuing review and
change because oil and gas prices fluctuate, proved reserves are developed or
new reserves added as a result of future drilling activities, and operation and
management services revenue and expenses vary. A minimum level of $9,000,000 of
future taxable income will be necessary to enable the Company to fully utilize
the net operating loss carryforwards and realize the gross deferred tax assets
of $3,329,000. This level of income can be achieved using the value of proved
reserves reported in the year end November 30, 1997 standardized measure of net
cash flows but this does not give total assurance that sufficient taxable income
will be generated for total utilization because of the volatility inherent in
the oil and gas industry which makes it difficult to project earnings in future
years due to the factors mentioned above. During 1997 the valuation allowance
was decreased by $262,000 related to pre-quasi- reorganization tax assets and
increased by $236,000 for post-quasi- reorganization assets. During 1996 the
valuation allowance was decreased by $409,000 related to
pre-quasi-reorganization tax assets and increased by $141,000 for
post-quasi-reorganization tax assets. During 1995 the valuation allowance was
increased $96,000.
(6) RELATED PARTY TRANSACTIONS
Reimbursement is made by Resources to Columbus for services provided by
Columbus officers and employees for managing Resources and reduces general and
administrative expense. This reimbursement totaled $255,000 for fiscal 1997,
$296,000 for fiscal 1996 and $213,000 for the nine months in 1995 following the
divestiture of Resources.
(7) CAPITAL STOCK
The shares and prices of stock options in this note have been adjusted to
reflect the five-for-four stock split in 1997 and 10% stock dividends in fiscal
1995 and 1994.
Columbus has several stock option plans with outstanding options for the
benefit of all employees. Under the 1985 Plan, options for 75,344 shares were
exercisable at November 30, 1997. No additional options may be granted under the
1985 Plan. At November 30, 1996, 91,789 shares were exercisable.
Under the 1995 Plan, as of November 30, 1997, 41,555 option shares remained
available for granting, and options for 300,490 shares were exercisable. Options
may be exercised for a period determined at grant date but not to exceed five
years. Options are vested in three equal annual amounts from grant date or each
part may be exercised immediately for each twelve-month period the optionholder
63
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
has been an employee of the Company. At November 30, 1996, 176,305 shares were
available for granting, and options for 225,543 shares were exercisable.
The Board of Directors has granted non-qualified stock options of which
there were 117,025 exercisable at November 30, 1997 and 115,245 shares were
exercisable at November 30, 1996.
On December 1, 1996, the Company adopted Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123). The
Company elected to continue to measure compensation costs for these plans using
the current method of accounting under Accounting Principles Board (APB) Opinion
No. 25 and related interpretations in accounting for its stock option plans.
Accordingly, no compensation expense is recognized for stock options granted
with an exercise price equal to the market value of Columbus stock on the date
of grant. Had compensation cost for the Company's stock option plans been
determined using the fair-value method in SFAS No. 123, the Company's net income
and earnings per share would have been as follows:
1997 1996
---- ----
(thousands except per share amounts)
Net Income
As reported $2,167 $2,098
Pro forma $1,968 $1,897
Earnings per share (primary)
As reported $ .55 $ .54
Pro forma $ .50 $ .49
64
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Options are granted at 100% of fair market value on date of grant. The
following table is a summary of stock option transactions for the three years
ended November 30, 1997:
1997 1996 1995
---------------- ---------------- ----------------
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
-------- ------- -------- ------- -------- -------
(options in thousands)
Shares under option at
beginning of year 445 $6.22 353 $5.77 421 $6.21
Granted 174 8.12 307 5.80 228 5.48
Exercised (110) 5.17 (202) 4.86 (50) 3.55
Surrendered or expired (3) 7.30 (13) 5.38 (246) 6.60
---- ---- ----
Shares under option at
end of year 506 7.09 445 6.22 353 5.77
==== ==== ====
Options exercisable
at November 30 493 7.01 433 6.22 324 5.75
Shares available for
future grant at end
of year 42 176 275
Weighted-average fair value
of options granted during
the year $2.24 $1.32 N/A
The following table summarizes information about the Company's stock
options outstanding at November 30, 1997:
Options Outstanding Options Exercisable
----------------------------------- ----------------------
Weighted-
Options Average Weighted- Options Weighted-
Range of Outstanding Remaining Average Exercisable Average
Exercise at Year Contractual Exercise at Year Exercise
Prices End Life (Years) Price End Price
-------- ----------- ----------- -------- ----------- --------
(options in thousands)
$5.15 - $5.90 88 1.3 $ 5.55 87 $ 5.56
$6.00 - $6.77 183 2.6 6.36 183 6.36
$7.80 - $8.63 235 3.5 8.22 223 8.22
--- --- ------ --- ------
$5.15 - $8.63 506 2.8 7.09 493 7.06
=== === ====== === ======
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:
1997 1996
---- ----
Expected option life - years 2.36 1.81
Risk-free interest rate 6.08% 5.64%
Dividend yield 0 % 0 %
Volatility 30.60% 23.14%
65
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of August 1, 1995, the Board of Directors authorized an exchange of new
stock option grants at the closing price ($6.625) on that date which equaled 80%
of all previously granted stock options. These could be surrendered at the
election of the holder provided that the holder previously had his monthly
salary reduced as a part of the downsizing and administrative cost reduction
program. Share options in the amount of 170,521 granted at prices from $5.87 to
$8.47 were canceled and 66,015 share options were reissued as of August 1, 1995
and 70,400 non-statutory share options were reissued on February 5, 1996 at the
fair market value of the Company's shares on that date.
On October 28, 1992, the Board of Directors approved an Employee Stock
Purchase Plan ("Plan") to begin January 1, 1993, which was approved by the
shareholders at the 1993 annual meeting. Under the Plan a total of 220,000
shares were reserved from authorized unissued common stock from which payments
by participants into the Plan will be utilized to purchase shares and the
Company will contribute an amount of shares equivalent to 25% of those payments
which will be issued out of the Company's treasury stock as vesting occurs
semi-annually. For the fiscal years 1997 and 1996 total matching contributions
of $15,000 and $13,000, respectively, were accrued as an expense by the Company.
The price of the issued shares equals the average trading price during each six
month purchase period or the ending price, whichever is less. During fiscal 1996
a total of 12,394 shares were purchased (2,492 shares from treasury stock as the
Company's contribution of 25%) at an average cost of $7.32 per share. During
fiscal 1997 a total of 8,758 shares were purchased (1,762 shares from treasury
stock for the Company contribution of 25%) at an average cost of $8.58 per
share.
The Company has been authorized by the Board of Directors to repurchase its
common shares from the market at various prices during the last several years.
Those repurchases are summarized as follows:
Shares
Fiscal year ------------------------- Average
repurchased As purchased Restated* price*
----------- ------------------------- -------
1995 243,200 247,730 $7.33
1996 86,100 107,625 $5.33
1997 158,000 179,875 $7.61
*Restated for stock split and stock dividends
66
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of November 30, 1997 a total of 143,000 shares remained out of the most
recent authorization which may be repurchased at a price not to exceed $8.875
per share. As of January 31, 1998, 49,650 of those shares have been acquired at
an average price of $8.60 per share.
(8) COMMITMENTS AND CONTINGENT LIABILITIES
The Company's Articles of Incorporation and By-Laws provide for
indemnification of its officers, directors, agents and employees to the maximum
extent authorized by the Colorado Corporation Code, as amended or as may be
amended, revised or superseded. In addition, the Company has entered into
individual indemnification agreements with its officers and directors, present
and past, which agreements more fully describe such indemnification.
Lease - In June 1991, Columbus executed a lease for office space for its
present building which provides for monthly payments of $11,123, plus
inflationary adjustments to an annual base operating expense, for a period of 60
months from October 1991 through October 1996. The total rent expense for 1997,
1996 and 1995 was approximately $161,000, $133,000 and $126,000, respectively.
Columbus has renewed the lease for an additional two years through September
1998 at a base rate of $13,536 per month. Future rental payments, without regard
to operating cost adjustments, required under this lease as of November 30, 1997
are $135,000 for fiscal year 1998.
Columbus is self-insured for medical and dental claims of its U. S.
employees and dependents as well as any former employees or dependents who are
eligible and elect coverage under COBRA rules. Columbus pays a premium to obtain
both individual and aggregate stop-loss insurance coverage. A liability for
estimated claims incurred and not reported or paid before year end is included
in other current liabilities.
The separation pay policy of Columbus includes a retirement provision.
Officers and employees may retire at age 65, or older, and at the discretion of
the Board of Directors be paid retirement compensation based upon the length of
service and last year's average compensation. Such compensation has been
approved for three individuals who have reached age 65. As of November 30, 1997
the accrued liability totals $201,000 which may change in future years until
their retirement as compensation and length of service with Columbus changes.
The total obligation is unfunded and payment upon an individual's retirement
will be made from working capital. The total expense accrued was $23,000 and
$16,000 in 1997 and 1996, respectively.
67
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In prior years Columbus has hedged both natural gas and crude oil prices by
selling a "swap". The swap is matched against the calendar monthly average price
on the NYMEX and settled monthly. Revenues are decreased when the market price
at settlement exceeded the contract swap price or increased when the contract
swap price exceeded the market price. The following table shows the results of
these swaps:
Increase (decrease) in
oil and gas revenues
Volume ----------------------
Description per mo. Period 1997 1996 1995
- ----------- ------- ------ ---- ---- ----
(Mmbtu or bbl)
Natural Gas
- -----------
$2.20/Mmbtu 60,000 3/97-10/97 $(86,400)
Futures Contracts 60,000 10/96-11/96 $ 42,000
$1.74 & $1.88/Mmbtu 120,000 4/96-11/96 $(560,000)
$2.12/Mmbtu 100,000 12/94- 4/95 $283,900
Crude Oil
- ---------
$21.17/bbl 10,000 11/96-10/97 $ 8,900 $ (23,800)
$17.25/bbl with
$19.50/bbl cap 10,000 1/96-12/96 $(22,500) $(232,300)
The Company's natural gas and crude oil swaps were considered financial
instruments with off-balance sheet risk which were in the normal course of
business to partially reduce its exposure to fluctuations in the price of crude
oil and natural gas. Those instruments involved, to varying degrees, elements of
market and credit risk in excess of the amount recognized in the balance sheets.
The Company had no natural gas or crude oil swaps outstanding as of November 30,
1997.
The Company is not aware of any events of noncompliance in its operations
with any environmental laws and regulations nor of any material potential
contingencies related to environmental issues. The exact nature of environmental
control problems, if any, which the Company may encounter in the future cannot
be predicted, primarily because of the changing character of environmental
requirements that may be enacted with applicable jurisdictions.
The litigation expenses in 1995 relate to two lawsuits. The first, Michael
Mattalino, Bruce L. Davis and Maris E. Penn vs. Columbus Energy Corp. filed on
April 23, 1993 was settled by agreement in September 1994. The second, Porter
Farrell II vs. Columbus Energy Corp. filed October 14, 1993 had Columbus' motion
for summary judgment granted on April 12, 1995 and the lawsuit was dismissed.
68
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(9) DEFINED CONTRIBUTION PENSION PLAN
The Company has a qualified defined contribution 401(k) plan covering all
employees. The Company matches, at its discretion, a portion of a participant's
voluntary contribution up to a certain maximum amount of the participant's
compensation. The Company's contribution expense was approximately $95,000,
$90,000, and $101,000 in the fiscal years 1997, 1996 and 1995, respectively.
69
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(10) 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:
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Operating revenues from unaffiliated services (a):
Oil and gas $13,788 $10,617 $ 7,927
Services 1,308 1,198 1,473
------- ------- -------
Total $15,096 $11,815 $ 9,400
======= ======= =======
Depreciation, depletion and amortization (b):
Oil and gas $ 3,238 $ 2,763 $ 2,638
Services 57 72 119
------- ------- -------
Total $ 3,295 $ 2,835 $ 2,757
======= ======= =======
Operating income (loss):
Oil and gas $ 4,714(c) $ 4,339(c) $ (870)(c)
Services 424 249 337
General corporate expenses (1,372) (999) (1,278)
------- ------- -------
Total operating income 3,766 3,589 (1,811)
Interest expense and other 170 262 211
------- ------- -------
Earnings before income taxes $ 3,596 $ 3,327 $(2,022)
======= ======= =======
Identifiable assets (b):
Oil and gas $21,917 $18,910 $15,238
Services 4,218 2,715 3,083
Other corporate - - -
------- ------- -------
Total $26,135 $21,625 $18,321
======= ======= =======
Additions to property and equipment:
Oil and gas $ 9,671 $ 7,167 $ 4,423
Services 7 12 31
------- ------- -------
Total $ 9,678 $ 7,179 $ 4,454
======= ======= =======
</TABLE>
(a) Approximately $105,000 of inter-segment revenues are included in service
revenues in 1995 and are offset by the same amounts in oil and gas operating
expenses.
(b) Other property and equipment have been allocated above to the oil and gas
and services segment based upon the estimated proportion the property is used by
each segment. Therefore, depletion, depreciation and amortization and
identifiable assets do not match the functional allocations in Note 3 to the
consolidated financial statements.
(c) Includes non-cash impairment loss of $2,179,000 in 1997, $165,000 in 1996
and $3,055,000 in 1995.
70
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 131, "Disclosures about Segments of
an Enterprise and Related Information," effective for fiscal years beginning
after December 15, 1997. The Company must apply this statement no later than its
fiscal year ending November 30, 1999. SFAS No. 131 requires disclosing segment
information using the "management approach" and replaces the "industry segment"
approach presented above using Statement No. 14. The segment information
presented is not expected to materially change when SFAS No. 131 is adopted.
The Company conducted its foreign operations in Canada until February 1995
through its wholly-owned subsidiary, CEC Resources Ltd.
Summarized financial information concerning the foreign operations which is
included in the preceding table is as follows:
1995
----
(in thousands)
Operating revenues from unaffiliated services (a):
Oil and gas $ 639
Services 150
-------
Total $ 789
=======
Depreciation, depletion and
amortization:
Oil and gas $ 116
Services 17
-------
Total $ 133
=======
Operating income:
Oil and gas $ 225
Services 106
General corporate expenses (121)
-------
Total operating income 210
Interest expense and other 1
=======
Earnings before income taxes $ 209
=======
Identifiable assets:
Oil and gas $ -
Services -
-------
Total $ -
=======
Additions to property and equipment:
Oil and gas $ 45
Services 27
-------
Total $ 72
=======
(a) Approximately $105,000 of inter-segment revenues are included in services
revenues in 1995 and are offset by the same amounts in oil and gas operating
expenses.
71
<PAGE>
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) 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: February 19, 1998 By: /s/ Harry A. Trueblood, Jr.
----------------------- ------------------------------
Harry A. Trueblood, Jr.
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
Principal Executive Officer
Chairman of the Board,
President, and Chief
/s/ Harry A. Trueblood, Jr. Executive Officer 2/19/98
-------------------------
Harry A. Trueblood, Jr.
Chief Operating Officer
Executive Vice President
/s/ Clarence H. Brown and Chief Operating Officer 2/19/98
-------------------------
Clarence H. Brown
Principal Accounting and Financial Officer
/s/ Ronald H. Beck Vice President 2/19/98
-------------------------
Ronald H. Beck
Majority of Board of Directors
/s/ Harry A. Trueblood, Jr. Director 2/19/98
-------------------------
Harry A. Trueblood, Jr.
/s/ Clarence H. Brown Director 2/19/98
-------------------------
Clarence H. Brown
/s/ J. Samuel Butler Director 2/19/98
-------------------------
J. Samuel Butler
/s/ William H. Blount, Jr. Director 2/19/98
-------------------------
William H. Blount, Jr.
72
EXHIBIT 11
COLUMBUS ENERGY CORP.
Statement of Computation of Per Share Earnings
(Unaudited)
(In Thousands Except Per Share Data)
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
Primary:
Based on weighted average shares outstanding including the effect of common
stock equivalents:
Weighted average shares
outstanding: 3,908 3,829 3,928 4,087 4,255
Incremental shares attributable
to dilutive stock options and
warrants outstanding based on
average market price during
the period calculated using
the treasury stock method 84 42 7 46 114
------- ------ ------ ------- -------
Total average common and
common equivalent shares 3,992 3,872 3,935 4,133 4,369
======= ====== ====== ======= =======
Net earnings (loss) $ 2,167 $ 2,098 $(1,495) $ 2,190 $ 3,806
======= ======= ====== ======= =======
Earnings (loss) per share:
Net earnings (loss) $ .54 $ .54 $ (.38) $ .53 $ .87
======= ======= ======= ======= =======
Note: Fully diluted earnings per share in 1995, 1994, and 1993 were
identical to the primary earnings per share. Fully diluted incremental
shares in 1996 and 1997 were 257,000 and 105,000 with total average
common and common share equivalent shares of 4,086,000 and 4,013,000,
respectively.
The number of shares and per share amounts from 1993-1994 have been
restated to reflect the 10% stock dividends issued in 1994 and 1995.
Also, the number of shares and per share amounts from 1993-1996 have
been restated for May 27, 1997 five-for-four stock split.
EXHIBIT 22
COLUMBUS ENERGY CORP.
SUBSIDIARIES
November 30, 1997
Name Ownership
---- ---------
Columbus Gas Services, Inc. 100%
EXHIBIT 23(a)
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Columbus Energy Corp. on Form S-8 (File No. 33-63336) Form S-8 (File No.
33-93156), Form S-8 (File No. 33-25743) of our report dated February 11, 1998,
on our audits on the consolidated financial statements of Columbus Energy Corp.
as of November 30, 1997 and 1996, and for the years ended November 30, 1997,
1996, and 1995, which report is included in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
Denver, Colorado
February 11, 1998
EXHIBIT 23(b)
(REED W. FERRILL & ASSOCIATES LETTERHEAD)
February 7, 1998
Columbus Energy Corp.
1660 Lincoln Street, Suite 2400
Denver, Colorado 80264
Reed W. Ferrill & Associates, Inc. consents to the use of its name and its
reports dated February 7, 1998 entitled "Columbus Energy Corp., Reserve and
Revenue Forecast as of November 30, 1997, Constant Prices and Costs" in whole or
in part, by Columbus Energy Corp. (Columbus) in Columbus' Form 10-K Report to
the Securities and Exchange Commission for the fiscal year ended November 30,
1997.
for and on behalf of
Reed W. Ferrill & Associates, Inc.
\s\ Reed W. Ferrill
------------------------
Reed W. Ferrill
President
RWF/mlb
EXHIBIT 23(c)
(HUDDLESTON & CO., INC. LETTERHEAD)
February 7, 1998
Columbus Energy Corp.
1660 Lincoln Street, Suite 2400
Denver, Colorado 80264
Huddleston & Co., Inc. consents to the use of its name and its report dated
January 7, 1998, entitled "Columbus Energy Corp., Berry R. Cox Field, Estimated
Reserves and Revenues, as of November 30, 1997, Constant Product Prices" in
whole or in part, by Columbus Energy Corp. (Columbus) in Columbus' Form 10-K
Report to the Securities and Exchange Commission for the fiscal year ended
November 30, 1997.
For and On Behalf of
HUDDLESTON & CO., INC.
\s\ Peter D. Huddleston
----------------------------
Peter D. Huddleston, P.E.
President
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE CONSOLIDATED BALANCE SHEET AS OF NOVEMBER 30, 1997 AND THE CONSOLIDATED
STATEMENT OF INCOME FOR THE YEAR ENDED NOVEMBER 30, 1997.
</LEGEND>
<CIK> 0000823975
<NAME> Columbus Energy Corp.
<MULTIPLIER> 1000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> NOV-30-1997
<PERIOD-START> DEC-01-1996
<PERIOD-END> NOV-30-1997
<EXCHANGE-RATE> 1.000
<CASH> 1,857
<SECURITIES> 0
<RECEIVABLES> 3,896
<ALLOWANCES> 116
<INVENTORY> 102
<CURRENT-ASSETS> 5,911
<PP&E> 35,856
<DEPRECIATION> 15,632
<TOTAL-ASSETS> 26,135
<CURRENT-LIABILITIES> 5,189
<BONDS> 0
0
0
<COMMON> 898
<OTHER-SE> 17,060
<TOTAL-LIABILITY-AND-EQUITY> 26,135
<SALES> 13,815
<TOTAL-REVENUES> 15,096
<CGS> 3,107
<TOTAL-COSTS> 11,330
<OTHER-EXPENSES> (4)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 174
<INCOME-PRETAX> 3,596
<INCOME-TAX> 1,429
<INCOME-CONTINUING> 2,167
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,167
<EPS-PRIMARY> 0.55
<EPS-DILUTED> 0.55
</TABLE>
