SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 1998 001-9872
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COLUMBUS ENERGY CORP.
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(Exact name of Registrant as specified in its Charter)
COLORADO 84-0891713
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(State of incorporation) (I.R.S. Employer Identification No.)
1660 Lincoln Street
Denver, Colorado 80264
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(Address of principal executive offices) (Zip code)
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
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, 1999 is $21,335,000.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of January 31, 1999
Outstanding at
Class January 31, 1999
------------------------------ ----------------
Common Stock, ($.20 par value) 4,000,588 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>
INDEX
Securities and Exchange Commission
Item Number and Description
PART I
Page
----
Item 1. Business..........................................................3
Item 2. Properties - Oil and Gas Operations ............................. 4
Item 3. Legal Proceedings................................................24
Item 4. Submission of Matters to a
Vote of Security Holders..................................24
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters...........................25
Item 6. Selected Financial Data..........................................26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................27
Item 8. Financial Statements and Supplementary Data......................41
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure....................41
PART III
Item 10. Directors and Executive Officers
of the Registrant.........................................41
Item 11. Executive Compensation...........................................41
Item 12. Security Ownership of Certain Beneficial
Owners and Management.....................................41
Item 13. Certain Relationships and
Related Transactions......................................41
PART IV AND SIGNATURES
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K.........................42
Signatures.......................................................72
2
<PAGE>
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. On September 1, 1998 Columbus
formed a Texas partnership named Columbus Energy, L.P. and is its general
partner. The partnership's limited partner is Columbus Texas, Inc., a Nevada
corporation, which is a wholly-owned subsidiary of Columbus. All of the
Company's oil and gas properties in Texas were transferred to the partnership
effective September 1, 1998. Columbus remains the operator of the properties.
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.
3
<PAGE>
During 1998 Columbus declared a 10% stock dividend distributed March 9,
1998 to shareholders of record as of February 23, 1998. 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. The 1998 dividend and 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.
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.
4
<PAGE>
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, 1998, 1997 and 1996.
<TABLE>
<CAPTION>
PROVED OIL AND GAS RESERVES
1998 1997 1996
---------------- ---------------- ----------------
Oil Gas Oil Gas Oil Gas
MBbl Mmcf MBbl Mmcf MBbl Mmcf
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year ........ 1,805 18,520 1,643 18,665 2,035 14,858
Revisions of previous
estimates ............. (713) 767 (127) 226 (278) (1,335)
Purchase of reserves ..... 1 320 -- -- 17 4,808
Extensions and discoveries 88 6,355 538 5,066 150 3,190
Production ............... (221) (3,499) (249) (3,370) (246) (2,686)
Sale of reserves ......... -- -- -- (2,067) (35) (170)
----- ------ ----- ------ ----- ------
End of year .............. 960 22,463 1,805 18,520 1,643 18,665
===== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year ........ 1,333 16,122 1,211 15,758 1,384 11,282
===== ====== ===== ====== ===== ======
End of Year............... 762 20,674 1,333 16,122 1,211 15,758
===== ====== ===== ====== ===== ======
</TABLE>
Proved Developed Producing Reserves
As of November 30, 1998, Columbus has approximately 621,000 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 97%, and Texas alone 62%, 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 14.4 billion cubic feet of
proved developed producing gas reserves. Texas properties account for 99% of
these 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.
5
<PAGE>
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 141,000 barrels of oil, or 15% of
its total proved oil reserves, and 6.3 billion cubic feet of natural gas, or 28%
of its total proved natural gas reserves.
Proved Undeveloped Reserves
Columbus' proved undeveloped reserves were approximately 198,000 barrels
and 1.8 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, Harris and Jim Hogg Counties, Texas, Montana and
North Dakota.
These reserves are expected to either be developed during 1999 or in the
future when oil prices again stabilize at levels which will yield a satisfactory
rate of return on investment when developed. Four locations in the Williston
Basin which had been carried for several years with proved undeveloped oil
reserves while awaiting adequate prices which would yield an acceptable rate of
return on investment when drilled were dropped at fiscal year end due to low
crude prices. This accounted for 211,000 barrels of the reduction in proved oil
reserves from fiscal 1997 to fiscal 1998.
6
<PAGE>
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)
1998 1997 1996
-------- -------- --------
Future oil and gas revenues ................. $ 53,271 $ 79,381 $ 98,555
Future cost:
Production cost ........................... (13,688) (21,856) (25,620)
Development cost .......................... (2,638) (5,401) (4,264)
Future income taxes ......................... (6,325) (11,531) (14,198)
-------- -------- --------
Future net cash flows ....................... 30,620 40,593 54,473
Discount at 10% ............................. (8,691) (10,422) (16,313)
-------- -------- --------
Standardized measure of discounted future net
cash flows ................................ $ 21,929 $ 30,171 $ 38,160
======== ======== ========
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
FOR THE THREE YEARS ENDED NOVEMBER 30, 1998
(thousands of dollars)
1998 1997 1996
-------- -------- --------
Balance, beginning of year .................. $ 30,171 $ 38,160 $ 21,392
Sale of oil and gas net of production costs (7,397) (10,708) (7,556)
Net changes in prices and production costs (12,034) (10,502) 19,446
Purchase of reserves ...................... 310 -- 5,158
Sale of reserves .......................... -- (1,320) (229)
Extensions, discoveries and other additions 6,896 9,660 8,309
Revisions to previous estimates ........... (3,406) (710) (4,905)
Previously estimated development costs
incurred during the period .............. 586 1,089 729
Changes in development costs .............. 2,066 229 570
Accretion of discount ..................... 3,730 4,653 2,416
Other ..................................... (2,066) (1,620) (1,571)
Change in future income taxes ............. 3,073 1,240 (5,599)
-------- -------- --------
Net increase (decrease) ..................... (8,242) (7,989) 16,768
-------- -------- --------
Balance, end of year ........................ $ 21,929 $ 30,171 $ 38,160
======== ======== ========
7
<PAGE>
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, 1998, 1997 and
1996. 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, 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 reserves were
$25,986,000 in 1998, $37,301,000 in 1997, and $46,530,000 in 1996. 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, 1998 the crude oil price
(including natural gas liquids) was $11.29 per barrel and the natural gas price
was $1.89 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.
8
<PAGE>
Both 1998 and 1997 fiscal years are good examples of why an average price
would be preferable in management's opinion since 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, 1998,
1997 and 1996. The reports on the reserves of the properties located in the
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 U.S. oil and gas production for each of the past three fiscal
years is shown on the following table:
Fiscal Year
---------------------------
1998 1997 1996
-------- ------- -------
Oil-barrels 221,000 249,000 246,000
Gas-Mmcf 3,499 3,370 2,686
During the fiscal year 1998, 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
1997. This data was reported on a gross operated basis inclusive of royalty
interest and, therefore, does not compare with Columbus' net reserves reported
for 1997.
Average price and cost per unit of production for the past three fiscal
years are as follows:
Fiscal Year
--------------------------
1998 1997 1996
------- ------- -------
Average sales price:
per barrel of oil ...... $13.22 $19.62 $19.42
per Mcf of gas ......... $ 2.18 $ 2.65 $ 2.15
Average production cost per
equivalent barrel ....... $ 4.00 $ 3.83 $ 4.35
Natural gas converted to oil at the ratio of six Mcf of natural gas to one
barrel of oil. Production costs for fiscal years 1998, 1997 and 1996 include
production taxes.
9
<PAGE>
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, 1998 Gross Net
- ----------------- ---------------- --------------
Oil Gas Oil Gas
--- --- --- ---
Wells 81 161 21 20
Acres 35,520 10,493
Undeveloped Properties
The following table sets forth the Company's ownership in undeveloped
properties:
November 30, 1998 Gross Acres Net Acres
- ----------------- ----------- ---------
Louisiana 23,376 2,271
Montana 12,980 7,706
New Mexico 840 630
North Dakota 1,790 395
Texas 6,792 3,256
------ ------
Total Undeveloped Properties 45,778 14,258
====== ======
10
<PAGE>
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.
<TABLE>
<CAPTION>
Year Ended November 30,
--------------------------------------------------------------
1998 1997 1996
---------------- ---------------- -------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY
Wells Drilled:
Oil ................ 2 1.10 2 1.45 -- --
Gas ................ 3 1.69 1 .37 -- --
Dry ................ 2 .92 1 .34 2 .68
DEVELOPMENT
Wells Drilled:
Oil ................ 1 .67 4 1.91 2 1.00
Gas ................ 8 1.06 18 2.71 14 2.60
Dry ................ 4 1.23 3 .65 6 2.95
TOTAL
Wells Drilled:
Oil ................. 3 1.77 6 3.36 2 1.00
Gas ................. 11 2.75 19 3.08 14 2.60
Dry ................. 6 2.15 4 .99 8 3.63
-- ---- -- ---- -- ----
Total ........... 20 6.67 29 7.43 24 7.23
== ==== == ==== == ====
</TABLE>
11
<PAGE>
Current Activities
During fiscal 1998, management shifted Columbus' emphasis and capital
budget almost entirely to the exploration for, and development of, natural gas
reserves. However, early in fiscal 1998 the Company was involved in completing a
well drilled in fiscal 1997, a successful 12,000-foot Red River formation oil
discovery in the Montana portion of the Williston Basin. Since the low crude oil
prices existing at the beginning of fiscal 1998 only got worse, Columbus also
limited its participation in drilling activities for oil to only when required
to prevent drainage. The 1998 budget formulated in November 1997 included some
3-D seismic plus exploration and development drilling on existing leasehold
blocks in the Williston Basin which was scrapped. Those funds were diverted to
an exploration program for natural gas reserves along the Texas Gulf Coast from
east of Houston to northwest of Corpus Christi. The 1998 budget also provided
for continued natural gas development drilling south of Laredo, Texas where
Columbus, or its former parent, has been involved for over 25 years. Although
natural gas prices weakened somewhat in latter fiscal 1998, they remained
sufficiently high for the capital expenditure budget of approximately $6.5
million to be completed. Actual cash expended during the 12 months exceeded $7.1
million, but this amount also included payment of significant accrued costs
associated with wells in progress as the prior year came to a close. The very
successful wildcat program resulted in three natural gas discoveries out of five
prospects drilled in this onshore Gulf Coast of Texas exploratory program which
has enhanced fiscal 1999's outlook for expanding natural gas reserves.
The more significant recent activities appear below and have been
segregated into Columbus' primary areas of operations:
South Texas - Laredo Area
- -------------------------
This continues to be the most important area for well operations since the
Company serves as operator of over 100 natural gas wells in various fields that
extend from the southern city limits of Laredo to the B. R. Cox field in Jim
Hogg, County approximately 80 miles to the south. In this area Columbus owns
working interests ranging from 1% to 53% in wells which it operates and less
than 10% in the relatively few wells where it does not.
For the past few years, Columbus has almost continuously kept at least one
rig drilling infill, extension, and new fault block locations. These were
identified by a 3-D seismic program which was conducted and interpreted in
1994-95. During 1998, drilling was halted on two occasions after some wells did
not find the expected new fault block reservoirs and were completed as
additional wells in existing producing fault blocks. Also, three locations
proved to be unsuccessful. As a consequence, during 1998 only seven (0.41 net)
successful natural gas wells were completed while three (0.62 net) dry holes
were drilled which compares with participation in 18 gross wells in 1997 and 12
gross wells in 1996.
12
<PAGE>
In the B. R. Cox field, Columbus attempted one recompletion effort of a gas
zone behind pipe in one of the two inactive gas wells in this field. This
workover had been postponed pending a large working interest owner's agreement
to advance their share of the funds or else suffer non-consent penalties. That
owner finally agreed to participate, but after the new zone flowed gas for a
short period, the casing collapsed in this old wellbore. None of the working
interest owners were willing to spend the funds required to remedy the problem
so the well is a candidate for farmout, sale, or abandonment. Two other proposed
recompletions in new zones behind pipe or to drill the one remaining undeveloped
location in this field await approval by other working interest owners. During
latter 1997, the Company sold a producing property from this field and is
currently considering selling the balance of its interests in existing wells and
leaseholds.
Sralla Road Field Area - Harris County, Texas
- ---------------------------------------------
This upper Gulf Coast area is located east of Houston and has been
Columbus' primary source of field level cash flow throughout the decade of the
1990's. During fiscal 1998, drilling operations continued to be successful as
Columbus, as operator, developed additional Jackson Sand crude oil and natural
gas reserves in four separate wells. Two oil development wells were drilled in
the field's north end in the oil leg of the reservoir in order to prevent offset
drainage and both wells were completed as flowing high gas/oil ratio wells. The
Company owns 67% and 65% working interests therein and a similar interest in the
Fig Orchard #1 gas well which was recompleted as a sidetracked gas producer
after the casing had collapsed in the original wellbore. The fourth well (19.5%
WI) was an exploratory well on the south end which was projected to extend the
gas cap of this Jackson Sand reservoir by about one and one-half miles but the
wellbore was on the other side of an unknown cross fault separating it from the
gas cap. It found an oil discovery instead as the Jones #1 tested 240 barrels of
oil per day flowing through an 8/64th choke and has remained shut-in pending
completion of a gas gathering system since no gas flaring is allowed. The
installation of a pipeline has proved a challenge since the Jones #1 is located
in an area with considerable residential development made up of both primary
homes and second homes near the San Jacinto River. Although Columbus operates
this well, the pipeline construction is being pursued by the largest working
interest owner in the Jones #1 who also owns most of the acreage and wells
nearby. Obtaining the permits necessary to install the gathering system has
proved very frustrating but is expected to be completed by the end of the first
quarter of fiscal 1999.
13
<PAGE>
About 20 miles east of the Sralla Road field, the Company participated in
July 1997 in a successful exploratory discovery in the Frio 16 Sand near the
famous old Anahuac field in Chambers County, Texas. The Syphrett Heirs #1
initially tested for 4.6 million cubic feet per day and has sold approximately
100 million cubic feet per month throughout fiscal 1998 and has been one of
Columbus' most prolific producers. The Company originally owned a 27.5% working
interest as of the end of fiscal 1997, but this was subsequently reduced by
"back-ins" to an approximate 26% working interest.
The Company owned a similar interest in approximately 600 acres of
leaseholds to the south of that discovery. Available seismic indicated that
there were two separate drillable prospects on this acreage which probably
needed to be tested before leases expired. These two seismic features are
separated by a fault with the largest being located on the downthrown side which
was chosen as the initial location for an exploratory test. The Quinn #1 was
drilled to the Frio 15 Sand at about 9,000 feet and a very thick sand section
was encountered but contained water with a slight show of natural gas and a
second test well is not planned at present.
Williston Basin Area
- --------------------
Prevailing low crude oil prices throughout fiscal 1998 brought potential
new activity in this area of operations to a halt. Unfortunately, a drilling
program had already been commenced during fiscal 1997 and had mostly been
completed prior to the sharp decline in crude oil prices. The 1997 3-D seismic
program on the southern portion of this block of Montana acreage indicated Red
River formation structures were present, but subsequent 3-D seismic in 1998
found no drillable deep structures. During the fall of 1997, one of those Red
River structures was tested and the 90%-owned McCabe Farms #1-4 well was
successfully completed in December 1997. This 12,000-foot well pumped initially
at a rate of 86 barrels of oil per day with a like amount of water which was
disappointing since such a high water cut had not been indicated on either the
logs or in a drillstem test. Subsequently, a second exploratory well tested a
Tyler Sand zone at about 7,000 feet which was a dry hole because the indicated
channel on 3-D seismic was filled with reworked shale and lime with only limited
sand. No further tests of this channel are planned. There was another test of
the Tyler Sand in North Dakota when a behind pipe zone was perforated in a cased
wellbore of a Mission Canyon producer which was ready for abandonment. It flowed
nitrogen at a rate in excess of 2 million cubic feet per day. Unfortunately,
there is no current market for a prolific nitrogen well having less than 10%
methane and it will most likely be abandoned during 1999. Also, continued low
crude oil prices resulted in over half of the operated wells in the Williston
Basin being rendered uneconomic and have either been shut down or else are being
operated only a few days of each month.
14
<PAGE>
Goudeau Prospect - Avoyelles and St. Landry Parishes, Louisiana
- ---------------------------------------------------------------
This deep geo-pressured Austin Chalk prospect proved to be a very
disappointing area for the industry in general and for Columbus in particular
even though it only participated in one re- entry well. The Morrow #23-1H was a
15,000-foot wellbore which had been cased and abandoned several years ago by an
unrelated operator when an attempted completion in a deeper horizon failed.
Belco Oil & Gas, as operator of the prospect and the major interest owner,
agreed to drill updip and downdip laterals of about 4,000 feet each in this
cased wellbore at no expense to Columbus and its co-venturers who had originated
this prospect area. However, Belco apparently became disenchanted after
completion of an updip lateral only. When it announced it would move on to
another well and not finish its obligation for a downdip lateral for Columbus
and co- venturers, there were strong exceptions taken. Following hasty
negotiations, Columbus et al took over the wellbore and Belco withdrew
altogether from the 2,560 acre unit. What ensued thereafter proved to be
expensive as numerous problems were encountered while drilling the downdip
lateral. These have been previously reported and need not be recounted here.
Therefore, instead of having a relatively small working interest and limited
cost exposure in this exploration well, Columbus et al bore the entire expensive
undertaking which bordered on a disaster because of attempted blowouts, lost
circulation, and mechanical problems with the drilling equipment. These became
so intense that the venturers settled for only a 1,200-foot downdip lateral. The
initial rate of produced fluid was extremely high from this short lateral at
over 66 barrels per hour but unfortunately only 21% was oil initially and during
its subsequent 14 months of production, this geo-pressured zone's flow rate has
declined slowly to only 11 barrels of oil per day as the percentage water cut
steadily increased. At current prices, the well is marginally economic but had
the cut been reversed, payout would probably have already been achieved. Any
further attempt to drill a second downdip lateral, or to open up the existing
updip lateral which is below bridge plugs and a whip stock, cannot presently be
justified based on current prices. Also, Columbus has no plans for additional
participation in drilling deep geo-pressured Austin Chalk wells in Louisiana so
this geologic province has been eliminated as a potential new core area.
El Squared Prospect - Bee County, Texas
- ---------------------------------------
This prospect area has been described in earlier 1998 quarterly reports and
news releases as one of the most exciting areas for potential reserve increases
that has been added as a new Columbus operational area since the Sralla Road
discovery east of Houston in 1990. At present this prospect's leaseholds have
grown to approximately 5,500 acres in size and prior to the Company becoming
involved were fully covered with a 3-D seismic program. Columbus currently owns
a 55% working interest (42% NRI) while three of its regular drilling associates
own 20% working interests and the oil company which originated the prospect owns
the remaining 25%. After acquiring participation, Columbus had the seismic data
processed and interpreted by an outside expert. Ownership rights in the initial
4,000-acre block acquired were limited by depth to formations below 7,000 feet
which in this immediate area primarily consists of several potentially
productive gas sands in the Wilcox formation from 9,000 feet to 17,000 feet. All
depths are available in the additionally acquired acreage.
15
<PAGE>
The initial interpretation of the 3-D seismic indicated there were several
significant "bright spots" as well as numerous separate fault blocks that
included both antithetic (up-to-the-coast) faults as well as normal
down-to-the-coast faults at various depths. Based on information in the general
area available from prior drilling as well as from producing fields nearby,
there are several different zones of the Wilcox formation with local names for
the sand intervals that are considered prospective in this leasehold block. In
the upper Wilcox there are two or three Slick Sands beginning at depths of about
9,500 feet, two or more Luling Sands beginning at about 10,200 feet, a Mackhank
Sand beginning around 11,300 feet, at least two Massive Sands beginning around
12,000 feet, and three or more Reagan Sands below 14,000 feet. Available
information also indicates that all of these reservoirs should be geo-pressured
with bottom hole pressures ranging from around 6,000 psi at the Slick Sand level
to over 13,000 psi in the deeper Reagan Sands. This indicates there can be
significant reserves of natural gas with porosities of 15% to 22% and a cut-off
at 10%. Initial seismic interpretation also indicated that there are probably
several individual fault blocks that range in size from small in surface area
(100 acres or less) up to several hundred acres. More important is that these
Wilcox Sands appear to have gross thicknesses of 40 feet to 180 feet so with the
reservoirs geo-pressured, significant accumulations of natural gas reserves in a
successful well can occur even if a fault block for a particular reservoir might
be small. This in effect defines this prospective area as one with vertical
reserves potential rather than one with a large geographic areal extent such as
the Hugoton field. This area may still require several wells fairly closely
spaced on the surface in order to exploit the reserves at the different levels
in their most structurally favorable positions.
The initial wellsite for the Long #1 was selected using 3-D seismic such
that the vertical wellbore would penetrate the upper Slick Sand immediately
underneath a sealing up-to-the-coast fault and place the Slick reservoirs near
the apex of their structure. While the deeper Luling Sand zones were expected to
be prospective even though further down on structure, they hopefully would be
found above their gas-water contacts. If this were not the outcome, a second or
even a third wellbore might be required to penetrate all Luling Sands
sufficiently high on structure. In the first well, the company who created the
prospect was carried to total depth for a 25% working interest only in the
initial test well and participated in the completion operation expenses.
16
<PAGE>
Columbus owns a 55% working interest (42% NRI) in the Long #1. It proved to
be a successful natural gas discovery and was completed in 38 feet of
perforations in two separate Slick Sand intervals which had gross thicknesses of
46 and 37 feet, respectively, between the depths of 9,704 and 9,835 feet. There
was also a third Slick Sand encountered in the Long #1 which had about 180 feet
of gross interval. It tested gas for a few hours at the rate of approximately
750 thousand cubic feet per day but also produced formation water and lost
circulation drilling mud from 40 feet of perforations in the cased hole which
were left open underneath a bridge plug to be produced later. Only the two upper
Slick zones were completed since electric logs indicated that the Luling "A" and
"B" Sands had fairly high water saturations, would probably be borderline gas
productive zones, and should be completed in another wellbore structurally
higher. The Long #1 was placed on production in early October and has sold about
60 million cubic feet per month along with six to eight barrels of condensate
per million cubic feet. Initially the Long #1 also produced formation salt water
at over 80 barrels per day but this rate declined fairly rapidly and is
currently about 25 barrels per day. Initial estimates of reserves for all of the
Long #1 Slick Sands producing as well as non-producing under the bridge plug
approximated eight billion cubic feet. With Columbus' net revenue interest of
about 42%, this was an extremely important addition to its reserves as well as
future cash flow.
Unfortunately, Wilcox Sands are known to have swelling clays that are very
sensitive to contact with water. Accordingly, fracture stimulation was initially
deferred for the Long #1 but a treatment is now being formulated and should be
undertaken in the very near future when a portion of the tubing string must be
replaced because of corrosion. Evidence of the severity of the clay problem in
this area could be more carefully examined in the second well, the Long #2,
because it did not have as much lost circulation problems. Management is
developing a program which will help overcome future severe wellbore damage
created while drilling through the sands or by subsequently allowing non-
treated fluids to come into contact with the producing sands. The latter problem
was observed recently in the Long #1 whereby merely shutting-in for treatment
for corrosion in the tubing production string actually reduced the well's flow
rate from approximately 2 million down to 1.7 million cubic feet per day.
Management has recently determined that even though this gas contains only 4%
carbon dioxide it appears that when this amount is combined with the produced
water that corrosion is occurring and must be addressed in both wells as well as
in future wells. By proper advance planning, these types of problems can be
reduced or overcome so there appear to be sizable reserves to be established
with appropriate safeguards and completion techniques. Although these wells
might be completed naturally with no fracture stimulation, it will become a
necessity at some point to facilitate recovery of sizable reserves in a more
reasonable period of time. An example is the postponed fracture stimulation
during original completion of the Long #1 which should now be undertaken in
order to open the undamaged reservoir to the wellbore. During the next few
weeks, a fairly limited stimulation which will probably use condensate as the
frac carrying fluid is proposed for this well and is expected to create a
significant improvement in its daily productive capability. Assuming this
initial treatment desatment design proves satisfactory, it will be employed in
future completions.ign proves satisfactory, it will be employed in future
completions.
17
<PAGE>
At the end of 1998, the Long #2 had been drilled to a total depth of 11,000
feet and had been cased with 7" production casing in anticipation that a dual
completion could be accomplished in the Slick and Luling Sand intervals. This
was based primarily on log analysis of each of the sands using the known values
for the Slick Sand formation water that was actually being produced in the Long
#1. This also assumed that the formation water in the third Slick Sand, the
Luling "A" Sand, and the Luling "B" Sand would have similar characteristics.
Furthermore, there was a wireline formation test run in the basal Luling "B"
interval which had fairly low resistivity on the logs yet recovered some gas and
water which was relatively fresh and interpreted as mud filtrate water. There
were significant indications of mud invasion into each of the sand intervals and
water from the wireline formation tester did not remotely resemble more heavily
salt saturated water from the Slick being produced only 700 feet away. Using the
resistivity of produced water in the calculations for gas saturation in each of
the main sand zones in the three prospective intervals, the logs indicated that
there was net gas pay in the wellbore which probably exceeded 140 feet. With the
known geo-pressured conditions present based on results from wireline pressure
tests, the reserve potential of this well appeared to be fairly sizable. Because
this potential addition to natural gas reserves appeared so significant,
management felt compelled to make a press release that would at least put
shareholders on notice of such a possibility even though the well had not yet
been perforated or tested in any of the zones at that point in time.
Insofar as the Long #2's third Slick Sand was concerned, it had produced
gas in the Long #1 previously and there was a wireline formation test which
yielded gas and a lesser amount of fresh mud filtrate water. Also, this sand was
about 140 feet structurally higher than the first well so management was fairly
confident as to its probable gas productivity. In the instance of the two Luling
Sands, they were not penetrated at their maximum structural position immediately
beneath the up-to-the-coast sealing fault in order that at least some of the
third Slick Sand would be present in the wellbore. These two Luling zones were
expected to be at least 100 feet higher structurally than in the Long #1 and it
wasassumed this amount would yield a sufficiently high structural position for a
water-free completion in those two sands. Management felt that sacrificing an
additional 150 feet of available structure would not prevent them from being
productive and it was important to get a dual zone gas completion at the Long #2
location.
18
<PAGE>
As so often occurs in the exploration phase of this business, results
obtained are not always what are anticipated using analogous information as a
guideline with which to formulate an opinion. For example, the basal ten feet of
the Luling "B" was interpreted on the logs as having low resistivity and was on
the borderline of indicated gas/water contact, but a wireline formation test did
yield some gas and mud filtrate water. It subsequently gave up water after
perforating with no show of gas and surprisingly the produced water from this
basal zone was significantly less saturated with sodium chlorides than the
produced water from the Long #1 Slick Sand interval. Assuming this water was a
representative sample of Luling water, it significantly changed all of the gas
saturation calculations that had been made for both of those zones. Presumably
the third Slick Sand calculations should not be affected. Using this new
resistivity, the basal 10 to 15 feet of the Luling "B" calculated high water
saturation but the remainder would be expected to produce gas along with
formation water. Complicating such calculations is the clay content of these
sands which tends to hold immobile water. Several feet which calculated as gas
pay were cement squeezed also in order that an attempt to separately test the
upper portion of the Luling "B" could be undertaken.
Obviously, management has been sorely disappointed with the Luling results
but has not been able to obtain a satisfactory explanation from experts in the
area as to how or why the salt saturations in the water from the Slick and
Luling zones can be so vastly different. Had management known such to be the
case, it would have entirely changed proposed completion procedures in the
various intervals with a more selective perforating program. The problem was
further exacerbated by the fact that apparently the primary cement job behind
the 7" casing is fairly poor according to a cement bond log. This limited the
ability to treat individual zones for formation damage which occurred during
drilling operations. Without treatment there can be no certainty that any gas
present in the sands will be produced along with the water recovered from the
Luling "B" during swabbing operations. Since the Luling "A" Sand appears to have
been similarly affected by drilling fluids and presumably contains the same
water characteristics found below, management decided to temporarily leave it
untested in this wellbore and proceed with a block squeeze cement program for a
third Slick Sand single zone completion.
19
<PAGE>
As of early February, 1999 the Long #2 had been successfully completed in
30 feet of perforations in the 120 foot lower Slick Sand zone from a depth of
9,906 to 9,936 feet which were fracture stimulated with 25,000 pounds of frac
sand using condensate as the carrying fluid. During initial cleanup, the well
flowed natural gas through a 11/64th inch choke at the rate of 1,781,000 cubic
feet per day along with frac condensate and water at a daily rate of 66 barrels
and six barrels respectively. Flowing tubing pressure was 3247 psi. The well
will be flowed on a temporary basis at this lower rate pending the construction
of a gathering line of larger diameter pipe.
It now appears evident that in order for these Luling Sands to be found
productive of natural gas and water free, they must be penetrated at the apex of
the structure which would place them as much as 150 feet structurally higher
than in the present Long #2 wellbore. While it is disappointing not to be able
to use this larger diameter casing for a dual completion, this will prove
helpful for drilling to the deeper and higher pressured formations in future. We
will be able to use large diameter drilling tools and cross the sealing fault at
the best possible structural position for either the Mackhank or the Massive
Sands of the middle Wilcox. There is also an alternative that a window can be
cut and a wellbore drilled directionally to the structural apex of the Luling
from this existing cased wellbore at a later date when the Slick reservoir has
been depleted.
Management has not wavered in its belief that this Prospect Area holds
significant potential for rapidly growing the Company's natural gas reserves.
However, it has become painfully evident from its experience with the first two
wells that further attempts to achieve dual completions in this type of high
structural relief environment is neither realistically practical nor truly a
money saving approach for rapid extraction of reserves. Each prospective
reservoir in every fault block apparently must be drilled at the optimum
structural position. Also, a drilling and completion program must be designed
which will minimize the damage to the clays contained in these sands. It is
extremely frustrating to have to accept producing wellbores in the range of 10
billion cubic feet of reserves instead of multiple sand completions with 25
billion cubic feet of reserves. Management must adopt this general concept as a
wellsite location guideline for most wellbores in this area in future.
Heidi Prospect - Jim Wells County, Texas
- ----------------------------------------
This Vicksburg formation gas prospect near Alice, Texas is fairly shallow
at 5,800 feet deep with three potentially productive sand zones which are known
locally as the Bierstadt, the Alice and the Stillwell sand in descending order
beginning at about 5,100 feet. In the initial discovery well, the latter sand
was tight with minimal shows while both the Alice and Bierstadt had excellent
gas shows in well developed sands but were extremely close to gas-water
contacts. Only the Bierstadt interval could be completed as a water free natural
gas discovery well and has been flowing for several months at about 300,000
cubic feet per day. Based on 3-D seismic conducted by another company which
became available in exchange for permission to shoot across these leaseholds, it
appeared that at least one or more well sites could be selected that could be 20
to 30 feet structurally higher than the Bernsen #1 discovery well at the
Vicksburg level and an interesting deeper structure appears prospective for a
test well for horizons in the Yegua and below. The Company owns a 62% working
interest (48% NRI) in this discovery well and the prospect area.
20
<PAGE>
Recently, the Company drilled the Bernsen #2 location using that 3-D
seismic data for the well site location and found the Bierstadt and Alice zones
about 16 feet and 24 feet higher structurally, respectively. For reasons not
entirely clear, the logs showed gas-water contacts to have moved up also with
the structural improvement although wireline formation tests of both zones
showed them to be gas productive. Since 4 1/2 inch casing was run in the well,
only the Bierstadt has been completed as a single zone gas producer in case
water has to be handled along with the gas. After perforating the zone, the well
instantaneously began flowing at the rate of approximately 200,000 cubic feet
per day through a small 6/64th inch choke with 1300 psi flowing tubing pressure
and no formation water. The well has been turned to sales and its flow rate will
continue to be highly restricted and monitored to make certain that bottom water
is not being coned upward after which time it will be increased. An offset well
will be required in due course to protect offsetting royalty owners not
presently included in this drill site.
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.
21
<PAGE>
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
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 four 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, 1998, 1997 and 1996, 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.
22
<PAGE>
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
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 and 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.
23
<PAGE>
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
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
On October 7, 1998, Columbus was served with a complaint in a lawsuit
styled Maris E. Penn, Michael Mattalino, Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98- 44940 in the District Court of
Harris County, Texas. The plaintiffs claim that Columbus breached the settlement
agreement reached in September 1994 of their previous lawsuit by failing to
develop properties located within the area of mutual interests and to act as a
reasonably prudent operator in the development of the property. Plaintiffs
allege damages under the contract but no amount is specified. Columbus has
responded with a First Set of Interrogatories to plaintiffs. Columbus denies all
of the plaintiffs' allegations.
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 1998, no matters were submitted to a vote of
security holders.
24
<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. The reported
high and low sales prices for the periods ending below were as follows:
High(1) Low(1)
------- ------
1999:
December 1, 1998 through
January 31, 1999 .................... $ 6.75 $ 6.50
1998:
First quarter .......................... $ 8.18 $ 7.125
Second quarter ......................... 7.875 7.00
Third quarter .......................... 7.50 6.375
Fourth quarter ......................... 6.69 6.25
1997:
First quarter .......................... $ 8.00 $ 6.27
Second quarter ......................... 7.64 6.14
Third quarter .......................... 7.84 6.82
Fourth quarter ......................... 8.30 7.05
1996:
First quarter .......................... $ 4.18 $ 3.64
Second quarter ......................... 5.82 3.91
Third quarter .......................... 8.27 5.09
Fourth quarter ......................... 7.91 6.91
(1) Price per share amounts have been adjusted for the 10% stock dividend
distribution to shareholders of record on February 23, 1998 and the
five-for-four stock split on May 27, 1997.
As of January 29, 1999 the reported closing sales price of Columbus common
stock was $6.625 per share.
As of November 30, 1998, there were approximately 440 holders of record of
Columbus' common stock and an estimated 900 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.
25
<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,
1998, were derived from the financial statements of the Company which have been
audited by PricewaterhouseCoopers LLP, 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,
----------------------------------------------------
1998 1997 1996 1995(a) 1994
--------- --------- --------- ---------- -------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Operating data:
Revenues ......................... $ 12,094 $ 15,096 $ 11,815 $ 9,400 $ 13,141
Loss on asset disposition,
impairment of long-lived
properties and abandonments .... (3,482) (2,179) (165) (3,055) --
Net earnings (loss) .............. (1,235) 2,167 2,098 (1,495) 2,190
======= ======= ======= ======= ======
Earnings (loss) per
share(b):
Basic .......................... $ (.29) $ .50 $ .50 $ (.35) $ .49
======= ======= ======= ======= ======
Diluted ........................ $ (.29) $ .49 $ .49 $ (.35) $ .48
======= ======= ======= ======= ======
Weighted average number of
common and common equivalent
shares outstanding(b):
Basic .......................... 4,194 4,299 4,211 4,321 4,495
======= ======= ======= ======= ======
Diluted ........................ 4,194 4,392 4,259 4,321 4,546
======= ======= ======= ======= ======
Cash flow data(d):
Cash from operating activities ... $ 6,258 $ 8,638 $ 5,638 $ 3,929 $ 6,194
Cash used in investing activities $ (6,717) $ (7,294) $ (6,320) $ (119) $ (7,194)
Cash provided by (used in)
financing activities(c) ........ $ 605 $ (883) $ 664 $ (4,223) $ 519
Cash flow before changes in
operating assets and liabilities $ 5,470 $ 9,132 $ 6,340 $ 3,920 $ 6,254
Discretionary cash flow .......... $ 6,192 $ 9,672 $ 6,658 $ 4,096 $ 6,715
Balance sheet data:
Total assets ..................... $ 23,949 $ 26,135 $ 21,625 $ 18,321 $ 24,955
Long-term debt, excluding
current maturities - bank debt . $ 4,900 $ 2,200 $ 2,200 $ 1,600 $ 4,200
Stockholders' equity ............. $ 15,264 $ 17,958 $ 16,225 $ 13,186 $ 16,202
</TABLE>
(a) Does not include results of CEC Resources Ltd. after its divestiture on
February 24, 1995.
(b) Reflects restated amounts for 1994 through 1997 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".
26
<PAGE>
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 1998 yielded the lowest average worldwide and domestic crude oil
prices in more than ten years for the domestic industry and for Columbus. The
Company's average natural gas prices were lower than in 1997 but natural gas
production was up 4% compared to 1997. Also, fiscal 1998 had substantially
higher exploration expenses and impairment charges that generated a net loss and
overshadowed record natural gas production. Those charges totaled $4,204,000
which, after being tax effected, reduced net earnings by $2,606,000 or $0.62 per
share and resulted in a loss of $1,235,000, or $0.29 per share. Discretionary
Cash Flow in 1998 of $6,192,000 was primarily reduced by weak product prices and
lower oil production and was significantly lower than 1997's record cash flow of
$9,672,000. Gross revenues and oil and gas sales were also lower in 1998 with
prices the primary culprit.
As of the end of 1998, shareholders' equity had decreased to $15,264,000
compared to $17,958,000 at November 30, 1997 due to higher exploration and
impairment charges and repurchase of treasury stock. Positive working capital of
$1,556,000 at year end, combined with the Company's anticipated cash flow for
1999 should provide sufficient funds for the expected fiscal 1999 capital
expenditure program. This primarily includes developing undeveloped reserves and
funding an exploratory program in the lower Gulf Coast area near its El Squared
discovery. Success to date with the Texas exploratory wildcats in this area has
been extremely encouraging. The unused portion of the $10,000,000 bank credit
facility has previously been primarily targeted by management for acquisitions
of oil and gas properties, but can be used for any legal corporate purpose and
also is available should there be unforeseen capital expenditures required
during 1999.
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 $5,600,000 to $8,600,000 during the last three years
which, coupled with use of the Company's credit facility, has provided
sufficient liquidity to fund those three years' oil and gas capital
expenditures, treasury share repurchases, and limited purchases of fractional
working interests in existing properties.
27
<PAGE>
However, management places greater reliance upon an important alternative
method of computing cash flow generally known as Discretionary Cash Flow ("DCF")
(which is not GAAP but is commonly used in the industry). This method calculates
cash flow before considering either working capital changes or deduction of
explora tion expenses as the latter can be increased or decreased at
management's discretion. DCF is often used by successful efforts companies when
making comparisons with the cash flow results of independent energy companies
which use the full cost accounting method where exploration expenses are
capitalized and therefore do not adversely affect either operating cash flow or
net earnings immediately. Columbus' DCF for 1998 was $6,192,000 which compared
to 1997's $9,672,000 (an all time record) and was a 36% decrease that was
primarily attributable to prevailing lower crude oil and natural gas prices. DCF
is also calculated without debt retirements being considered but in Columbus'
case it does not matter since outstanding bank debt requires no principal
payments before August 1, 2000. Interest expense on the outstanding debt has
been relatively insignificant and is always deducted before computing DCF
anyway.
Management continues to note in all public filings and reports 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. This position is based on our belief such a requirement
by GAAP ignores entirely the significant impact that the timing of income
received for, and expenses incurred on behalf of, third party owners in
properties has on working capital where Columbus owns only a small working
interest but is the operator.
However, neither DCF nor operating cash flow before working capital changes
may be substituted for net income or for cash available from operations as
defined by GAAP. Furthermore, currently reported cash flows, however defined,
are not necessarily indicative that there will be sufficient funds for all
future cash requirements. For 1998 GAAP cash flow was higher than DCF and, for
the prior two years, it was the reverse.
At the present time the Company has no hedges in place of either crude oil
or natural gas prices similar to those swaps it negotiated in prior years as
discussed below. Therefore, the Company's current oil and gas revenues are fully
exposed to risk of declining prices such as have occurred most of fiscal 1998.
Thus, it will be able to fully benefit from any price increases should these
occur during fiscal 1999.
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<PAGE>
In prior years Columbus hedged both natural gas and crude oil prices by
entering into "swaps" which were matched against the calendar monthly average
price on the NYMEX and settled monthly. Revenues were 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
- ----------- -------------- ----------- ---------- ----------
(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)
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,
1998.
Columbus had outstanding borrowings of $4,900,000 as of November 30, 1998
against its $10,000,000 line of credit with Norwest Bank Denver, N.A. which is
collateralized by its oil and gas properties. At the end of 1998, the ratio of
bank debt to shareholders' equity was 0.32 and to total assets was 0.20. The
outstanding debt used a LIBOR option with an average interest rate of 6.7%.
Subsequent to year end through January 31, 1999, the debt was decreased by
$200,000 to $4,700,000. The net increase (or decrease) in long- term debt
directly affects cash flows from financing activities as do the purchase of
treasury shares and proceeds from the exercise of stock options.
Working capital at 1998 year end remained positive at $1,556,000 compared
to $722,000 at November 30, 1997. This was achieved despite capital expenditures
of $5,763,000 for additions to oil and gas properties as well as the purchase of
352,766 shares of treasury stock for $2,550,000 during the year and benefited
from a $528,000 increase in current portion of deferred income taxes.
29
<PAGE>
The Company has been authorized by its 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*
----------- ------------ --------- -------
1996 86,100 118,388 $4.85
1997 158,000 197,863 $6.92
1998 352,750 357,715 $7.07
*Restated for stock split and stock dividends
As of November 30, 1998 a total of 123,922 shares remained to be purchased
from the most recent authorization at a price not to exceed $8.25 per share. As
of January 31, 1999, 52,600 of those shares have been acquired at an average
price of $6.60 per share.
During 1998, capital expenditures actually incurred on oil and gas
properties totaled $5,763,000 which amount differs from the capital expenditure
shown in the Consolidated Statement of Cash Flows. The latter also includes cash
payments made during 1998 for 1997 expenditures incurred but not yet paid as of
1997's year end. Similarly, there have been expenditures accrued in 1998 that
will not be actually paid until 1999. These were primarily for the exploratory
program in the Texas Gulf Coast area.
Impact of the Year 2000 issue. The Year 2000 issue is the result of
computer programs being written using two digits rather than four, or other
methods, to define the applicable year. Computer programs that have
date-sensitive software may recognize a date using "00" as the year 1900 rather
than the year 2000 and could result in a system failure or miscalculations
causing disruptions of operations such as a temporary inability to process
transactions, transmit invoices or engage in similar normal business activities.
The Company upgraded its major system computer software in 1997 to a new
release of a major software vendor that is compliant with the year 2000.
Columbus has started its review of other less important systems as well as its
significant suppliers, purchasers, and transporters of oil and gas to determine
the extent to which the Company might still be vulnerable to other failures and
what the impact might be on its operations.
The Company's interest in wells operated by other companies is not
considered to be as important but management is attempting to determine if those
companies are ready for the year 2000. Outside services are used for payroll and
medical benefits processing and those companies provided updates to their
software that is year 2000 compliant by year-end 1998. The Company is also
somewhat dependent upon personal computers as well as certain spreadsheet and
word processing software programs which may not be year 2000 ready at present.
Evaluations will be made to establish which of those systems are critical and
need to be remedied.
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<PAGE>
The Company also relies on non-information technology systems, such as
office telephones, facsimile machines, air conditioning, heating and elevators
in its leased office building, which may have embedded technology such as micro
controllers and are generally outside of its control to assess or remedy. These
might adversely impact the Company's business but in management's opinion would
not create a material disruption.
As previously disclosed, the major system computer software upgrade
performed in 1997 cost $16,000. Management expects that this represents the
majority of the costs, including replacement of any non-compliant information
technology system, required to meet its goal of being year 2000 ready for
mission-critical systems. The Company does not believe that any loss of revenue
will occur as a result of the year 2000 problem but regardless of efforts to
identify and remedy such problems, there could be year 2000 related failures
that cause some disruption. The Company has not established a contingency plan
should year 2000 failures occur and has not determined if it will in fact create
a contingency plan.
Results of Operations
The Company's 1998 gross revenues of $12.1 million were 20% below 1997's
and, as noted previously, the decrease was caused primarily by lower prices.
Because of continued low crude oil prices, over half of the Company's operated
wells in the Williston Basin have been rendered uneconomic and have either been
shut down or are being operated only a few days each month. Furthermore, 1997
gross revenues of $15.1 million were 28% above 1996's which was attributable to
higher prices and what was then a record level of natural gas production plus
improved crude oil production generated by the Company's 1997 drilling program.
The operating loss of $1,706,000 in 1998 was a direct result of a
significant increase in impairments, lower revenues, plus higher lease operating
expenses and exploration costs versus 1997. Operating income of $3,766,000 in
1997 represented an improvement of only 5% over 1996 but without higher
exploratory charges and impairment provisions, the increase would have been 59%.
The 1998 net loss of $1,235,000 was primarily attributable to the
impairment expense although all of the factors previously discussed contributed
to this result. Net earnings during 1997 set a new high from U.S. only
operations of $2,167,000 which surpassed 1996 earnings of $2,098,000. Had there
not been the extremely high non-cash impairment provisions during 1997, record
net earnings would have surpassed earlier years' results which also included
Canadian operations.
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<PAGE>
Impairments
The fiscal 1998 non-cash impairment loss of $3,482,000 was recognized
during the first and fourth quarters with provisions of $2,816,000 and $666,000
respectively. The primary cause for each was the continued low crude oil prices
which showed signs of recovery throughout the year but had retreated to the lows
by year end. This resulted in a significant reduction in total reserve
quantities which are based on the SEC calculation method using constant prices.
The carrying value of remaining unamortized costs in several successful efforts
pools still exceeded the resultant undiscounted future net cash flows even when
determined using somewhat higher crude prices than were currently being
realized. Several property pools had been initially written down as of the end
of the first quarter to a fair value based on an assumption that the average
future crude oil price over the life of reserves would be $18.75 per barrel.
This was lowered to $14 at year end based on bearish longer term sentiments
expressed by many noted experts. The actual $11.50 year-end price calculation
eliminated certain proved undeveloped locations as no longer being economic and
it also further shortened the economic productive life of most oil wells. When a
$14 price was used over the life of the reserves, it required an additional
non-cash impairment for the fourth quarter of $666,000 although some undeveloped
oil reserves would be restored.
There was a $400,000 charge included in the first quarter provision for
probable loss in value of undeveloped acreage and abandonments of leaseholds
located primarily in Louisiana which was in addition to the $200,000 reserved in
1997. This Louisiana Austin Chalk horizontal well, the Morrow #23-H, had
reserves originally assigned to an extension of the current downdip lateral but
were eliminated by price and performance and contributed heavily to the first
quarter provision. Also, the necessary recompletion workover to place the updip
lateral on production was theoretically postponed. Although economic at a $14
per barrel crude oil price, this recompletion was deferred for two more years
for expected better prices which altered the present worth of those reserves and
also contributed to the fourth quarter provisions.
Non-cash impairment losses of $243,000 for 1997 and $165,000 for 1996 was
recognized for certain Oklahoma development oil and gas wells completed in prior
years which had become marginal. During the third quarter of 1997, despite the
fact that a production test of the Morrow #23-1H had not yet occurred,
management chose to write off as impaired certain small leaseholds in the
acreage block where the possibility of putting together a drilling unit before
exploration was rather remote. Also included were leaseholds where annual
rentals were already due or about to be due. These non-cash write downs amounted
to $251,000 bringing the total impairment provision during the third quarter of
1997 to $494,000.
32
<PAGE>
As fiscal 1997 closed, it became clearer that because of increasing water
cuts the Morrow #23-1H's oil production rates would be less than the initial
potential tests had indicated. Accordingly, 1997's year-end proved reserves
attributable to both horizontal legs were reduced which resulted in further
impairment charges of $1,140,000 related to this Louisiana well and $84,000 to
leaseholds. As previously indicated, a general provision for all undeveloped
leaseholds was recorded in the amount of $200,000 where, based upon management's
opinion, further development probably could not be completed in time prior to
lease expirations. Also, two oil wells in Oklahoma which had failed to respond
to attempts to eliminate shifting frac sand from halting production were charged
with additional impairment of $260,000 of the total 1997 year end amount. Those
wells have not been abandoned permanently and may be returned to production when
better crude prices are available.
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 under the caption 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
------------ --------------- --------------
1998 vs. 1997
Gas ............. (18)% 4 % (14)%
Oil ............. (33)% (11)% (40)%
1997 vs. 1996
Gas ............. 23 % 25 % 53 %
Oil ............. 1 % 1 % 3 %
Columbus' 1998 record sales volumes of natural gas averaged 9,703 Mcf per
day while oil and liquids production declined to 606 barrels per day and equate
to daily production of 2,223 barrels of oil equivalent (BOE). This was
essentially flat with daily production of 2,229 BOE during 1997.
With the 4% increase in natural gas production during 1998 and a decrease
of 11% in oil production, the Company now produces approximately 73% of its
volumes from natural gas. This swing in percentage resulted from the emphasis
change initiated by management last year and has proved to be a correct shift as
the price of crude oil remained at low levels.
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<PAGE>
Natural gas revenues for 1998 decreased 14% compared to 1997 primarily as a
result of lower prices which overcame improved gas production from new wells in
the Texas Gulf Coast area. These new discoveries offset normal annual production
declines plus the sale of a Berry R. Cox field property in Texas during fourth
quarter 1997. Average prices for natural gas decreased 18% compared to 1997 with
a lack of increased demand due to a warm winter and the highest percentage of
storage refill ever accomplished during 1998.
Oil revenues for 1998 were down by a significant 40% compared with 1997 as
a result of a substantial 33% decrease in the average price plus a lower sales
volume of 11%. The latter directly reflected a very sharp decline of a 90%-owned
Montana oil well which had been recompleted uphole during 1997's third quarter
and contributed its initial flush production for the last few months of last
year. Furthermore, during 1998's third quarter, several oil wells became
marginal because of low prices and were shut down. Also, any well which had pump
or tubing problems was not repaired nor were workovers performed as needed.
Unfortunately no crude oil swap was in place during 1998 to offer protection
from this latest price debacle but was in place during a portion of 1997 when
prices were high.
Natural gas revenues in 1997 increased 53% over 1996's as a result of both
higher volumes and prices. Average prices for natural gas increased 23% in 1997
versus 1996 due to strong demand and a fairly tight supply of gas in excess of
storage injection requirements. Gas revenues for 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 in those years. Sales volumes improved by 25% over 1996 as
a result of numerous gas wells being completed and connected in Texas later in
the preceding year and early 1997.
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 normal decline over a several year period because new oil wells
were completed in 1997 which generated such an improvement. New oil and
condensate production in Montana and Chambers County, Texas during 1997 was
essentially 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.
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.
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<PAGE>
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 and no oil hedges existed in 1995. Crude oil production in 1996
improved because of two new Jackson sand oil well completions in the Sralla Road
field plus a third well (78% WI) gas condensate discovery extended the field one
mile southwest and commenced production in November. These increases overcame
normal production declines elsewhere.
U.S. oil prices have fluctuated for several years with the same wide swings
experienced in world crude oil price. During 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 steadily
softened and declined each quarter. This trend continued during most of 1998 and
ended the year at about $11.50 per barrel.
Lease operating expenses increased 16% in 1998 over 1997 because of
expensive workovers along with downhole and surface equipment replacements on
several older wells. 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 replaced. Lease operating expenses
for U.S. wells only increased 23% in 1996 over 1995 because of incremental
working interest acquisitions and several extensive work-overs performed. Lease
operating costs on a barrel of oil equivalent basis for 1998 rose to $2.63
compared to $2.27 in 1997 but down from $2.80 for 1996. Operating costs as a
percentage of revenues increased to 20% in 1998 due to lower prices and higher
costs. During 1997 they decreased to 13% due to increased production and product
prices while they were 19% in 1996 with lower prices and production.
Production and property taxes approximated 10% of revenues in 1998 and 1996
and 9% of revenues in 1997. 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.
35
<PAGE>
Operating and Management Services
This segment of the Company's business is comprised of operations and
services conducted on behalf of third parties including compressor rentals and
salt water disposal facilities. Operating and management services revenue has
increased in each of the last three years.
Operating and management services gross profit was $276,000 during 1998
compared to a $349,000 profit during 1997. This decline was due to unusually
high 1998 workover expenses required to clean out sand from the well bore of a
salt water disposal well in Texas. Revenues improved during 1998's second half
as the number of operated wells and drilling activity increased along with an
increase from 50% to 100% ownership interest in four compressors operating in
South Texas.
Operating and management services 1997 profit of $349,000 compared to a
$210,000 profit for 1996 because the number of operated wells and drilling
activity increased in 1997.
Interest Income
Interest income is earned primarily from short-term investments whose rates
fluctuate with changes in the commercial paper rates and the prime rate.
Interest income decreased in 1998 to $141,000 when compared to $147,000 in 1997,
reflecting a decreased amount of investments and lower short-term interest
rates. Interest income increased slightly in 1997 to $147,000 compared to 1996
as a result of higher short-term interest rates realized and despite a decreased
amount of investments.
General and Administrative Expenses
General and administrative expenses are considered to be those which relate
to the direct costs of the Company which do not originate from operation of
properties or providing of services. Corporate expense represents a major part
of this category.
The Company's general and administrative expenses for 1998 were 7% higher
than last year due primarily to higher medical claims and increased incentive
bonuses. These bonuses are discretionary and directly related to the Company's
performance during the prior year (not 1998) and totaled $273,000 ($153,000
non-cash) as of May, 1998 compared to $220,000 ($70,000 non-cash) in May, 1997.
Also, some cost increases in 1998 resulted from salary adjustments granted
effective December 1, 1997 for non-officer employees as well as May 1, 1998 for
officers. Medical claims under the Company's self- insured plan vary from year
to year with no discernible pattern. For 1998 legal and accounting expenses
decreased because 1997 had included costs related to a registration statement
which was canceled.
36
<PAGE>
Reimbursement for services provided by Columbus officers and employees for
managing Resources decreased during 1998 and is scheduled to end on March 31,
1999. Columbus provided Resources with a 90-day notice of termination of the
Services Contract and will completely withdraw from providing personnel
services. Resources elected a new President and Chief Executive Officer who
purchased a 4.5% equity position in Resources as of June 30, 1998 and he has
subsequently added to Resources' staff. Columbus' general and administrative
expense will rise commensurately since staff reductions are not presently
contemplated although some contract services should be reduced. Reimbursement of
$218,000 for 1998 compares with $255,000 during 1997 and $296,000 in 1996 was
received for providing services to Resources.
The Company's general and administrative expenses in 1997 were similarly
higher than 1996's due to salary increases in May 1997 for officers and in
December 1996 for employees along with incentive bonuses in May 1997. The latter
were discretionary and were actually based on the Company's performance in 1996.
Total bonuses of $220,000 ($70,000 non-cash) in 1997 compared to $83,000 (all
non-cash) in 1996. Another major source of this increase in 1997 was legal and
accounting expenses which had been accrued in connection with preparation of a
registration statement which was withdrawn because of the rapid paydown of debt
from accelerating cash flow.
The Company's expenses for 1996 were lower than for all of 1995 because
salary and staff reductions occurred in August 1995 which affected the whole
year. Also, incentive bonuses (all non-cash) totaled only $83,000 in 1996
compared to $110,000 granted in May, 1995.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are
calculated based upon the units of production for the period compared to proved
reserves of each successful efforts property pool. This expense is not only
directly related to the level of production, but also is dependent upon past
costs to find, develop and recover related reserves in each of the cost pools or
fields. Depreciation and amortization of office equipment and computer software
is also included in the total charge.
This expense item for 1998 increased over 1997 as a result of increased
production and development expenditures which occurred in the intervening period
while there was a reduction in reserves in several cost pools brought about by
lower crude oil prices. Total charges for depletion expense for oil and gas
properties increased for 1997 over 1996 due to increased production and added
development expenditures during the intervening period. Total charges for
depletion expense for oil and gas properties increased in 1996 over 1995 due to
greater production and despite the benefit realized from the 1995 write-down of
the carrying value of certain properties upon adoption of SFAS-121.
37
<PAGE>
Directly related to reduced crude oil reserves in certain cost pools the
depletion and depreciation rate for fiscal 1998 reached $4.64 per barrel of oil
equivalent ("BOE"). This compared to $3.91 per BOE for fiscal 1997 and $3.86 per
BOE in 1996.
Effective October 1, 1997 the Company sold its fractional working interests
in seven wells in the Berry Cox field in Texas for cash proceeds of $750,000.
These wells were a part of a larger pool of properties in the general 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 may result
in 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. The
successful efforts method of accounting for oil and gas properties requires
expensing the costs of unsuccessful exploratory wells. Other exploratory charges
such as seismic and geological costs must also be immediately expensed
regardless of whether a prospect is ultimately proved to be successful. All such
exploration charges not only decrease net earnings but also reduce reported GAAP
cash flow from operations even though they are discretionary expenses; however,
such charges are added back for purposes of determining DCF which is why it more
nearly tracks cash flow reported by full cost accounting companies who
capitalize such costs.
Exploration expense for 1998 of $722,000 included two exploratory dry
holes. In the S.E. Froid area in Montana $209,000 was expensed while in the
Texas Gulf Coast area the second dry hole cost $142,000. At present no
exploratory oil wells can be justified on any of the 3-D seismic structures
mapped on the Company's Williston Basin leasehold blocks in Montana until crude
oil prices significantly improve. Early in 1998 3-D seismic costs of $135,000
were incurred in this area in anticipation there would be an improvement in
crude oil prices and because of leasehold expirations due to occur during 1999.
Exploration charges for 1997 were also up significantly 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, and $73,000
incurred for drilling a non-commercial exploratory oil well.
During 1996 $184,000 was expensed when two Oklahoma exploratory wells
drilled proved non-economic. 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 a total exploration
expense of $245,000.
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<PAGE>
Litigation Expense
The litigation expense in 1998 relates to the Maris E. Penn, et al lawsuit
previously described for which charges have only just begun.
Interest Expense
Interest expense varies in direct proportion to the amount of bank debt and
the level of bank interest rates. The average amount outstanding has been higher
during 1998 than in 1997. The average bank interest rate paid for debt in 1998,
1997 and 1996 was 7.1%, 7.1%, and 7.2%, respectively.
Income Taxes
The Company's income tax position is complex. 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 1998, 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 1999 and thereafter unless an active drilling
program is maintained. In addition, the Company pays state income taxes.
During 1998, the net deferred tax asset was $210,000 and is comprised of a
$327,000 current portion and a $117,000 long-term tax liability. The valuation
allowance was decreased by a net $35,000. A deduction of $156,000 for the
benefit of stock options that were exercised was added to additional paid-in
capital.
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<PAGE>
During 1997, there was a net deferred tax liability of $989,000 which was
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.
During 1996, the net deferred tax asset was reduced to $1,000 which was
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.
New Accounting Pronouncements
SFAS 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 will not have a material impact on the Company's financial statements.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," effective for fiscal years beginning after
June 15, 1999. The Company must apply this statement no later than its fiscal
year ending November 30, 2000. SFAS No. 133 requires recording all derivative
instruments as assets or liabilities measured at fair value. This Statement is
not expected to materially affect the Company's financial statements.
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 could again be adversely affected by any recurrence of such economic
conditions although in general, inflation 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 inordinately affected.
Oil and gas prices have also been somewhat 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 but have recently begun to drop as drilling
programs have been cutback by most companies. 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.
40
<PAGE>
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 44.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Items 10 and 11. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
AND EXECUTIVE COMPENSATION
A definitive proxy statement related to the 1999 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 1999 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 1999 Annual Meeting of Stockholders and is
incorporated herein by reference.
41
<PAGE>
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K
(a) Financial statements and schedules
included in this report:
See "Index to Consolidated Financial Statements" on page 44.
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 1998:
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) First Amendment of Credit Agreement dated September 8, 1998
between Columbus Energy Corp. and Norwest Bank Colorado,
National Association (Exhibit 10(a) to Form 10-Q dated
August 31, 1998).
*10(c) Second Amendment of Credit Agreement dated October 6, 1998
between Columbus Energy Corp. and Norwest Bank Colorado,
National Association (Exhibit 10(b) to Form 10-Q dated
August 31, 1998).
42
<PAGE>
*10(d) 1993 Stock Purchase Plan (Exhibit to Registration Statement
No. 33-63336).
*10(e) 1995 Stock Option Plan (Exhibit 10(k) to Form 8-K dated May
11, 1995).
*10(f) 1985 Stock Option Plan (Exhibit to Registration Statement
No. 33-17885).
*10(g) 1985 Stock Option Plan, Amendment No. 2 dated November 7,
1991 (Exhibit 10(h) to Form 10-K dated November 30, 1991).
*10(h) 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(i) Form of Indemnity Agreements with directors (Exhibit 10(k)
to Registration Statement No. 33-46394).
22 Subsidiaries of the Registrant.
23(a) Consent of PricewaterhouseCoopers LLP.
23(b) Consent of Reed W. Ferrill & Associates, Inc.
23(c) Consent of Huddleston & Co., Inc.
27 Financial Data Schedule
_______________
*Incorporated by reference
43
<PAGE>
COLUMBUS ENERGY CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants 45
Financial Statements:
Consolidated Balance Sheets at
November 30, 1998 and 1997 46
Consolidated Statements of Operations for the
years ended November 30, 1998, 1997 and 1996 48
Consolidated Statements of Stockholders'
Equity for the years ended
November 30, 1998, 1997 and 1996 49
Consolidated Statements of Cash Flows for the
years ended November 30, 1998, 1997 and 1996 51
Notes to the Consolidated Financial Statements 52
44
<PAGE>
Report of Independent Accountants
To the Board of Directors and Stockholders
of Columbus Energy Corp.
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, shareholders' equity and cash
flows present fairly, in all material respects, the financial position of
Columbus Energy Corp. and its subsidiaries at November 30, 1998 and 1997, and
the consolidated results of their operations and their cash flows for each of
the three years in the period ended at November 30, 1998, in conformity with
generally accepted accounting principles. 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 of these statements in
accordance with generally accepted auditing standards which 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, assessing the accounting
principles used and significant estimates made by management, and evaluating the
overall consolidated financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Denver, Colorado
February 10, 1999
45
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
November 30,
---------------------
1998 1997
-------- --------
(in thousands)
Current assets:
Cash and cash equivalents .......... $ 2,003 $ 1,857
Accounts receivable:
Joint interest partners .......... 1,570 1,932
Oil and gas sales ................ 1,239 2,054
Allowance for doubtful accounts .. (116) (116)
Deferred income taxes (Note 5) ..... 327 --
Inventory of oil field equipment,
at lower of average cost or market 95 102
Other .............................. 106 82
-------- --------
Total current assets .............. 5,224 5,911
-------- --------
Property and equipment:
Oil and gas assets, successful
efforts method (Notes 3 and 4) ... 36,039 33,803
Other property and equipment ....... 1,804 2,053
-------- --------
37,843 35,856
Less: Accumulated depreciation,
depletion, amortization and
valuation allowance
(Notes 2 and 3) .................. (19,118) (15,632)
-------- --------
Net property and equipment ....... 18,725 20,224
-------- --------
$ 23,949 $ 26,135
======== ========
(continued)
46
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
November 30,
---------------------
1998 1997
-------- --------
(in thousands)
Current liabilities:
Accounts payable $ 1,846 $ 3,023
Undistributed oil and gas
production receipts 317 393
Accrued production and property taxes 677 551
Prepayments from joint interest owners 374 565
Accrued expenses 415 377
Income taxes payable (Note 5) 2 42
Deferred income taxes (Note 5) - 201
Other 37 37
------- ------
Total current liabilities 3,668 5,189
------- ------
Long-term bank debt (Note 4) 4,900 2,200
Deferred income taxes (Note 5) 117 788
Commitments and contingent liabilities (Note 9)
Stockholders' equity:
Preferred stock authorized 5,000,000
shares, no par value; none issued - -
Common stock authorized 20,000,000 shares
of $.20 par value; 4,611,001 shares
issued in 1998 and 4,492,068 in 1997
(outstanding 4,046,552 in 1998 and
3,883,557 in 1997) (Notes 1 and 7) 922 898
Additional paid-in capital 19,656 18,124
Retained earnings (accumulated deficit) (1,440) 2,887
------- -------
19,138 21,909
Less:
Treasury stock, at cost (Note 7)
564,449 shares in 1998 and
608,511 shares in 1997 (3,874) (3,951)
------- -------
Total stockholders' equity 15,264 17,958
------- -------
$23,949 $26,135
The accompanying notes are an integral part of
these consolidated financial statements.
47
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended November 30,
---------------------------------
1998 1997 1996
-------- -------- -------
(in thousands, except per share data)
<S> <C> <C> <C>
Revenues:
Oil and gas sales ....................................................... $ 10,617 $ 13,815 $10,572
Operating and management
services .............................................................. 1,336 1,176 1,087
Gain (loss) on sale of assets ........................................... -- (60) 31
Interest income and other ............................................... 141 165 125
-------- -------- -------
Total revenues ................................................... 12,094 15,096 11,815
-------- -------- -------
Costs and expenses:
Lease operating expenses ................................................ 2,140 1,849 1,965
Property and production taxes ........................................... 1,080 1,258 1,051
Operating and management
services .............................................................. 1,060 827 877
General and administrative .............................................. 1,466 1,372 999
Depreciation, depletion and
amortization ........................................................... 3,846 3,295 2,835
Impairments ............................................................. 3,482 2,179 165
Exploration expense ..................................................... 722 540 318
Litigation expense ...................................................... 4 10 16
-------- -------- -------
Total costs and expenses ............................................. 13,800 11,330 8,226
-------- -------- -------
Operating income (loss) .............................................. (1,706) 3,766 3,589
-------- -------- -------
Other (income) expense:
Interest ................................................................ 260 174 260
Other ................................................................... 26 (4) 2
-------- -------- -------
286 170 262
-------- -------- -------
Earnings (loss) before
income taxes ..................................................... (1,992) 3,596 3,327
Provision (benefit) for income
taxes (Note 5) ....................................................... (757) 1,429 1,229
-------- -------- -------
Net earnings (loss) ........................................... $ (1,235) $ 2,167 $ 2,098
======== ======== =======
Earnings (loss) per share (Note 8):
Basic ................................................................. $ (.29) $ .50 $ .50
======== ======== =======
Diluted ............................................................... $ (.29) $ .49 $ .49
======== ======== =======
Weighted average number of common and common equivalent shares outstanding:
Basic ................................................................. 4,194 4,299 4,211
======== ======== =======
Diluted ............................................................... 4,194 4,392 4,259
======== ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
48
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Three Years Ended November 30, 1998
<TABLE>
<CAPTION>
Retained
Common Stock Additional Earnings Treasury Stock
---------------- Paid-in (Accumulated ---------------------
Shares Amount Capital deficit) Shares Amount
------- ------ ---------- ------------ ------ ---------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1995 ............ 3,328,580 $666 $ 15,842 $(1,378) 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 17,361 720 344,569 (2,556)
--------- ---- -------- ------- -------- -------
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
</TABLE>
49
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - (continued)
For the Three Years Ended November 30, 1998
<TABLE>
<CAPTION>
Retained
Common Stock Additional Earnings Treasury Stock
---------------- Paid-in (Accumulated ---------------------
Shares Amount Capital deficit) Shares Amount
------- ------ ---------- ------------ ------ ---------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
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 2,887 608,511 (3,951)
--------- ---- -------- ------- -------- ---------
Exercise of employee
stock options ............ 109,910 22 592 -- 27,193 (229)
Purchase of shares ......... -- -- -- -- 352,766 (2,550)
Shares issued for Stock
Purchase Plan ............ 9,023 2 70 -- (2,275) 16
10% stock dividend ......... -- -- 492 (3,092) (386,494) 2,598
Shares issued for
Incentive Bonus Plan
and directors' fees ...... -- -- (57) -- (35,252) 242
Tax benefit of stock option
exercises ................ -- -- 215 -- -- --
Income tax benefit of
loss carryforwards
arising prior to
quasi-reorganization ..... -- -- 220 -- -- --
Net loss ................... -- -- -- (1,235) -- --
--------- ---- -------- -------- --------- ---------
Balances,
November 30, 1998 ........ 4,611,001 $922 $ 19,656 $(1,440) 564,449 $ (3,874)
========= ==== ======== ======= ======== =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
50
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended November 30,
-------------------------------
1998 1997 1996
-------- ------- -------
(in thousands)
<S> <C> <C> <C>
Net earnings (loss) ................................................... $(1,235) $ 2,167 $ 2,098
Adjustments to reconcile net earnings (loss) to
net cash provided by operating activities:
Depreciation, depletion, and
amortization ..................................................... 3,846 3,295 2,835
Impairments and loss on asset dispositions ........................ 3,482 2,179 165
Deferred income tax provision (benefit) ........................... (822) 1,328 1,148
Other ............................................................. 199 163 94
Changes in operating assets and liabilities:
Accounts receivable ............................................... 1,177 (1,554) (358)
Other current assets .............................................. (7) 21 (38)
Accounts payable .................................................. (298) 352 (22)
Undistributed oil and gas production receipts ..................... (76) 339 (294)
Accrued production and property taxes ............................. 126 (4) (80)
Prepayments from joint interest owners ............................ (191) 307 69
Income taxes payable (receivable) ................................. 18 9 41
Other current liabilities ......................................... 39 36 (20)
------- ------- -------
Net cash provided by operating activities ......................... 6,258 8,638 5,638
------- ------- -------
Cash flows from investing activities:
Proceeds from sale of assets ...................................... 36 1,005 606
Additions to oil and gas properties ............................... (6,642) (8,172) (6,863)
Additions to other assets ......................................... (111) (127) (63)
------- ------- -------
Net cash used in investing activities ............................. (6,717) (7,294) (6,320)
------- ------- -------
Cash flows from financing activities:
Proceeds from long-term debt ...................................... 3,400 3,000 3,400
Reduction in long-term debt ....................................... (700) (3,000) (2,800)
Proceeds from exercise of stock options ........................... 455 498 643
Purchase of treasury stock ........................................ (2,550) (1,381) (579)
------- ------- -------
Net cash provided by (used in)
financing activities ............................................ 605 (883) 664
------- ------- -------
Net increase (decrease) in cash and cash equivalents .................. 146 461 (18)
Cash and cash equivalents at beginning of year ........................ 1,857 1,396 1,414
------- ------- -------
Cash and cash equivalents at end of year .............................. $ 2,003 $ 1,857 $ 1,396
======= ======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest ........................................................ $ 254 $ 182 $ 250
======= ======= =======
Income taxes, net of refunds .................................... $ 47 $ 91 $ 41
======= ======= =======
Supplemental disclosure of non-cash investing and financing activities:
Non-cash compensation expense
related to common stock ......................................... $ 190 $ 98 $ 114
======= ======= =======
Oil and gas property additions for stock .......................... $ -- $ -- $ 253
======= ======= =======
Use of loss carryforwards credited to
additional paid-in-capital ...................................... $ 220 $ 262 $ 409
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
51
<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. On September 1, 1998 Columbus
formed a Texas partnership named Columbus Energy, L.P. and is its general
partner. The partnership's limited partner is Columbus Texas, Inc. ("Texas"), a
Nevada corporation, which is a wholly- owned subsidiary of Columbus. All of the
Company's oil and gas properties in Texas were transferred to the partnership
effective September 1, 1998. Columbus remains the operator of the properties.
Columbus and its subsidiaries are referred to in these Notes to the Financial
Statements as the "Company".
(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 management's 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 Texas. All significant
intercompany balances have been eliminated in consolidation.
Cash Equivalents
For purposes of the statement of cash flows, the Company considers all
highly liquid debt instruments purchased with an original maturity of three
months or less to be cash equivalents. Hedging activities are included in cash
flow from operations in the cash flow statements.
52
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1998 and 1997 the Company had investments
in commercial paper of $1,100,000 and $900,000, respectively. The carrying
amounts of accounts receivable and accounts payable approximate their fair
values based on the short-term nature of those instruments. 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.
Expenditures for lease acquisition and development costs (tangible and
intangible) 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,
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.
53
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Provision for depreciation and depletion of capitalized exploration and
development costs are computed on the unit-of-production method based on proved
reserves of oil and gas, as estimated by petroleum engineers, on a property by
property basis. Unproved properties are assessed periodically to determine
whether they are impaired. When impairment occurs, a loss is recognized by
providing a valuation allowance. When leases for unproved properties expire, any
remaining cost is expensed.
An impairment loss on oil and gas properties is reported as a component
of income from continuing operations. The Company recognizes an impairment loss
when the carrying value exceeds the expected undiscounted future net cash flows
of each property pool at which time the property pool is written down to the
fair value. Fair value is estimated to be a discounted present value of expected
future net cash flows with appropriate risk consideration.
The Company 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 balancing
of gas production. The Company's gas imbalances are immaterial at November 30,
1998 and 1997.
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 is provided on the straight line method over their estimated useful
lives.
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.
54
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Earnings Per Share
The Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, "Earnings per Share," effective for the 1998 fiscal year.
Prior period earnings per share data presented has been restated to conform with
the provisions of SFAS No. 128. The purpose of SFAS No. 128 is to simplify the
computation of earnings per share. The new standard replaces the calculation of
"primary earnings per share" with a calculation called "basic earnings per
share" and redefines "diluted earnings per share".
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. Common stock
equivalents include shares issuable upon assumed exercise of dilutive stock
options using the average price for diluted shares. Historical average number of
shares outstanding and earnings per share have been adjusted for the
five-for-four stock split distributed June 16, 1997 to shareholders of record as
of May 27, 1997 and the 10% stock dividend distributed March 9, 1998 to
shareholders of record as of February 23, 1998.
Accounting for Stock-Based Compensation
The Financial Accounting Standards Board ("FASB") issued SFAS No. 123,
"Accounting for Stock-Based Compensation" in 1995. This statement prescribes the
accounting and reporting standards for stock-based employee compensation plans
and was effective for the Company's 1997 fiscal year. The Company makes the
alternative pro forma disclosures as permitted in the SFAS.
New Accounting Pronouncements
SFAS 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 will not have a material impact on the Company's financial statements.
55
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In June 1997, the FASB issued 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 using SFAS No. 14. The segment information previously presented is not
expected to materially change when SFAS No. 131 is adopted.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," effective for fiscal years beginning after
June 15, 1999. The Company must apply this statement no later than its fiscal
year ending November 30, 2000. SFAS No. 133 requires recording all derivative
instruments as assets or liabilities measured at fair value. This Statement is
not expected to materially affect the Company's financial statements.
(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,
-------------------
1998 1997
------- -------
Proved properties $35,290 $33,074
Unproved properties 749 729
------- -------
36,039 33,803
Less accumulated depreciation,
depletion, amortization and
valuation allowance (17,919) (14,175)
------- -------
Total net properties $18,120 $19,628
======= =======
56
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities
(in thousands)
Year Ended November 30,
---------------------------
1998 1997 1996
------ ------- ------
Property acquisition
costs:
Proved $ 74 $ -- $3,025
Unproved 764 508 976
Exploration costs 722 540 318
Development costs 4,925 9,043 3,115
------ ------- ------
Total costs incurred $6,485 $10,091 $7,434
====== ======= ======
Results of Operations for Producing Activities
(in thousands)
Year Ended November 30,
-------------------------------
1998 1997 1996
-------- ------- -------
Sales $ 10,617 $13,815 $10,572
Production (lifting)
costs (a) 3,220 3,107 3,016
Exploration expenses 722 540 318
Impairment of long-
lived assets 3,482 2,179 165
Depreciation
depletion and
amortization (b) 3,743 3,194 2,703
-------- ------- -------
(550) 4,795 4,370
Imputed income tax
provision (benefit) (209) 1,905 1,614
-------- ------- -------
Results of operations
from producing
activities
(excluding overhead
and interest
incurred) $ (341) $ 2,890 $ 2,756
======== ======= =======
(a) Production costs include lease operating expenses, production
and property taxes
(b) Amortization expense per equivalent barrel of production:
1998 - $4.64 1997 - $3.91 1996 - $3.86
57
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
For the years ended November 30, 1998, 1997 and 1996, 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.
1998 1997 1996
------------------ ------------------ -------------------
Amount % Revenue Amount % Revenue Amount % Revenue
------ --------- ------ --------- ------- ---------
Customer A $1,652 15.6% $2,956 21.4% $ 3,142 29.7%
Customer B 5,204 49.0 6,536 47.3 5,513 52.2
Customer C - - 1,395 10.1 1,212 11.5
Customer D 1,321 12.4 - - - -
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.
58
<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 September 8,
1998 the Credit Agreement was amended to extend the revolving period to July 1,
2000 when it entirely 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 1.50%. In
addition, a commitment fee of 1/4 of 1% of the average unused portion of the
credit is payable quarterly.
At November 30, 1998 outstanding borrowings on the revolving line of
credit were $4,900,000 and the unused borrowing base available was $5,100,000.
The $4,900,000 bears interest at LIBOR rate of 5.15% plus 1.50%.
The Agreement as amended provides that certain financial covenants be
met which include a minimum net worth of $12,000,000 plus 50% of Cumulative Net
Income, as defined, minus exploration expenses after August 31, 1998, 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, as defined, 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,:
1999 $ -
2000 544
2001 1,633
2002 1,634
2003 1,089
-------
Total $ 4,900
=======
59
<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):
1998 1997 1996
------- ------ ------
Current:
Federal $ -- $ 13 $ 2
State 65 88 79
------- ------ ------
65 101 81
------- ------ ------
Deferred:
Federal (789) 942 288
Use of loss carryforwards -- 347 848
State (33) 39 12
------- ------ ------
(822) 1,328 1,148
------- ------ ------
Total income tax
provision (benefit) $ (757) $1,429 $1,229
======= ====== ======
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
---------------------------
1998 1997 1996
------ ------ -----
U.S. Statutory rate (34)% 34 % 34 %
State income taxes 2 2 6
Change in valuation
allowance (4) 2 4
Percentage depletion -- - (7)
Other (2) 2 --
--- - --
Effective rate (38)% 40 % 37 %
=== == ==
The Company files a consolidated income tax return with its
subsidiaries. Consolidated income taxes are payable only when taxable income
exceeds available net operating loss carryforwards and other credits.
The Tax Reform Act of 1986 limits the use of corporate tax
carryforwards in any one taxable year if a corporation experiences a 50% change
of ownership. Columbus experienced such a change of ownership in October 1987
which limits its use of pre-change ownership net operating losses to
approximately $900,000 in each subsequent year.
60
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company uses the asset and liability method to account for income
taxes. Under this method, deferred tax liabilities and assets are determined
based on the temporary differences between financial statement and tax basis of
assets and liabilities using enacted rates in effect for the year in which the
differences are expected to reverse. Deferred tax assets (net of a valuation
allowance) primarily result from net operating loss carryforwards, percentage
depletion and certain accrued but unpaid employee benefits. Deferred tax
liabilities result from the recognition of depreciation, depletion and
amortization in different periods for financial reporting and tax purposes.
Because of the Company's previous 1987 quasi-reorganization, the
Company is required to report the effect of its net deferred tax asset arising
prior to December 1, 1987 as an increase in stockholders' equity rather than as
an increase to net earnings.
During fiscal 1998, certain tax assets (shown in the table below) were
utilized and the valuation allowance was decreased during the year by $35,000.
The tax effect of significant temporary differences representing deferred tax
assets and liabilities and changes were as follows (in thousands):
<TABLE>
<CAPTION>
Current Year
-----------------------
Dec. 1, Stockholders' Operations/ Nov. 30,
1997 Equity Other 1998
------- ----------- ----------- --------
<S> <C> <C> <C> <C>
Deferred tax assets:
Pre-1987 loss carryforwards $ 1,053 $-- $ 71 $ 1,124
Post-1987 loss carryforwards 540 -- -- 540
Percentage depletion
carryforwards 1,304 -- 174 1,478
State income tax loss
carryforwards 105 -- 13 118
Other 327 -- 2 329
------- ---- ----- -------
Total 3,329 -- 260 3,589
Valuation allowance (long-term) (1,443) 221(a) (186) (1,408)
------- ---- ----- -------
Deferred tax assets 1,886 221 74 2,181
------- ---- ----- -------
Tax benefit of stock option
exercises -- 156(a) (156) --
------- ---- ----- -------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (2,875) -- 904 (1,971)
------- ---- ----- -------
Net tax asset (liability) $ (989) $377 $ 822 $ 210
======= ==== ===== =======
_____________
(a) Credited to additional paid-in capital.
</TABLE>
61
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company has approximate net operating loss carryforwards (in
thousands) available at November 30, 1998 as follows:
Net
Expiration Year Operating Loss
--------------- --------------
1999 $ 2,014
2000 906
2001 387
2010 1,589
-------
$ 4,896
=======
For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of approximately $6,268,000 as of November 30, 1998. The Company
also has percentage depletion carryforwards of $3,890,000 which do not expire.
State income tax operating loss carryforwards of approximately $1,950,000 are
available at November 30, 1998.
The earnings before income taxes for financial statements differed from
taxable income as follows (in thousands):
1998 1997 1996
------- ------- -------
Earnings (loss) before income taxes
per financial statements $(1,992) $ 3,596 $ 3,327
Differences between income
before taxes for financial
statement purposes and
taxable income:
Intangible drilling costs
deductible for taxes (2,771) (6,158) (1,520)
Excess of book over tax
depletion, depreciation
and amortization 1,816 1,683 754
Tax benefit of stock option
exercises (229) (200) (273)
Impairment expense 3,426 1,843 165
Lease abandonments (74) (13) (117)
Other (23) 153 (95)
------- ------- -------
Federal taxable income $ 153 $ 904 $ 2,241
======= ======= =======
62
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1998 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 essentially utilize the NOL's before they expire. Of the
total valuation allowance of $1,408,000 as of November 30, 1998, $516,000
relates to pre-quasi- reorganization tax assets and the balance of $892,000
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.
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 $9,500,000 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 $3,589,000. This level of income can be achieved using the value of proved
reserves reported in the year end November 30, 1998 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 1998 the valuation allowance
was decreased by $221,000 related to pre-quasi- reorganization tax assets and
increased by $186,000 for post-quasi- reorganization assets. 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.
(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 $218,000 for fiscal 1998,
$255,000 for fiscal 1997 and $296,000 for fiscal 1996.
(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
1998, 1995 and 1994.
63
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Columbus has several stock option plans with outstanding options for the
benefit of all employees. Under the 1985 Plan, options for 63,731 shares were
exercisable at November 30, 1998. No additional options may be granted under the
1985 Plan. At November 30, 1997, 82,878 shares were exercisable.
Under the 1995 Plan, as of November 30, 1998, 6,937 option shares remained
available for granting, and options for 314,182 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
annual amount may be exercised immediately for each twelve-month period the
optionholder has been an employee of the Company. At November 30, 1997, 45,711
shares were available for granting, and options for 330,539 shares were
exercisable.
The Board of Directors has granted non-qualified stock options of which
there were 231,803 exercisable at November 30, 1998 and 128,728 shares were
exercisable at November 30, 1997. The Board of Directors has reserved 350,000
shares of treasury stock to be used for issuing common stock when non-qualified
stock options are exercised.
On December 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation". 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:
1998 1997 1996
-------- ------ ------
(thousands except per share amounts)
Net income (loss)
As reported $(1,235) $2,167 $2,098
Pro forma (1,392) $1,968 $1,897
Earnings (loss) per
share (primary)
As reported $ (.29) $ .50 $ .50
Pro forma $ (.33) $ .46 $ .45
64
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Options are granted at 100% of fair market value on the date of grant. The
following table is a summary of stock option transactions for the three years
ended November 30, 1998:
1998 1997 1996
----------------- ----------------- ----------------
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 557 $6.45 490 $5.65 388 $5.25
Granted 182 6.76 191 7.38 338 5.27
Exercised (115) 5.34 (121) 4.70 (222) 4.42
Expired (5) 7.79 (3) 6.64 (14) 4.89
---- ---- ----
Shares under option at
end of year 619 6.73 557 6.45 490 5.65
==== ==== ====
Options exercisable
at November 30 610 $6.73 542 $6.42 476 $5.65
Shares available for
future grant at end
of year 170 46 194
Weighted-average fair value
of options granted during
the year $1.40 $2.04 $1.20
The following table summarizes information about the Company's stock
options outstanding at November 30, 1998:
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)
$4.68 - $5.79 124 1.0 $ 5.48 124 $ 5.48
$6.03 - $6.44 136 3.0 6.30 133 6.29
$7.00 - $7.84 359 2.5 7.33 353 7.33
--- --- ------ --- ------
$4.68 - $7.84 619 2.3 6.73 610 6.73
=== === ====== === ======
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:
1998 1997 1996
---- ---- ----
Expected option life - years 2.32 2.36 1.81
Risk-free interest rate 5.02% 6.08% 5.64%
Dividend yield 0 % 0 % 0 %
Volatility 25.87% 30.60% 23.14%
65
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 1998 and 1997 total matching contributions
of $17,000 and $15,000, 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 1998
a total of 11,298 shares were purchased (2,275 shares from treasury stock as the
Company's contribution of 25%) at an average cost of $7.73 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*
----------- ------------ --------- -------
1996 86,100 118,388 $4.85
1997 158,000 197,863 $6.92
1998 352,750 357,715 $7.07
*Restated for stock split and stock dividends
66
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
As of November 30, 1998 a total of 123,922 shares remained out of the
most recent authorizations which may be repurchased at a price not to exceed
$8.25 per share. As of January 31, 1999, 52,600 of those shares have been
acquired at an average price of $6.60 per share.
(8) EARNINGS PER SHARE
The following table provides a reconciliation of basic and diluted
earnings per share (EPS):
Fiscal Year Ended November 30,
------------------------------------
1998 1997 1996
---------- ---------- ------------
(in thousands, except per share data)
Reconciliation of basic and diluted
EPS share computations:
Income (loss) available to common
shareholders - basic and
diluted EPS (numerator) $(1,235) $2,167 $2,098
====== ===== =====
Shares (denominator):
Basic EPS 4,194 4,299 4,211
Effect of dilutive option
shares - 93 48
----- ----- -----
Diluted EPS 4,194 4,392 4,259
===== ===== =====
Per share amount:
Basic EPS $ (.29) $ .50 $ .50
===== ===== =====
Diluted EPS $ (.29) $ .49 $ .49
===== ===== =====
Number of shares not included
in basic EPS that would have
been antidilutive because
exercise price of options was
greater than the average market
price of the common shares 138 73 152
===== ===== =====
Historical average number of shares outstanding and earnings per share
have been adjusted for the five-for-four stock split distributed June 16, 1997
to shareholders of record as of May 27, 1997 and the 10% stock dividend
distributed March 9, 1998 to shareholders of record as of February 23, 1998.
67
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(9) 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.
In June 1991, Columbus executed a lease for office space for its present
building. The total rent expense for 1998, 1997 and 1996 was approximately
$171,000, $161,000 and $133,000, respectively. Columbus has extended the lease
for an additional one year through September 1999 at a base rate of $17,655 per
month. Future rental payments required under this lease as of November 30, 1998
are $177,000 for fiscal year 1999.
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 the prior year's average compensation. Such compensation has been
approved for three individuals who have reached age 65. As of November 30, 1998
the accrued liability totals $220,000 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 $18,000,
$23,000 and $16,000 in 1998, 1997 and 1996, respectively.
68
<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 entering into "swaps". There was no hedging activity in fiscal 1998. The swap
was matched against the calendar monthly average price on the NYMEX and settled
monthly. Revenues were 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
- ----------- ------- ------ ---- ----
(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)
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 entered into in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those instruments 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, 1998.
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.
On October 7, 1998, Columbus was served with a complaint in a lawsuit
styled Maris E. Penn, Michael Mattalino, Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98- 44940 in the District Court of
Harris County, Texas. The plaintiffs claim that Columbus breached the settlement
agreement reached in September 1994 of their previous lawsuit by failing to
develop properties located within the area of mutual interests and to act as a
reasonably prudent operator in the development of the property. Plaintiffs
allege damages under the contract but no amount is specified. Columbus has
responded with a First Set of Interrogatories to plaintiffs. Columbus has denied
the plaintiffs' allegations.
69
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(10) 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 $106,000,
$95,000, and $90,000 in the fiscal years 1998, 1997 and 1996, respectively.
70
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(11) 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:
1998 1997 1996
---- ---- ----
(in thousands)
Operating revenues from
unaffiliated services:
Oil and gas $10,631 $13,788 $10,617
Services 1,464 1,308 1,198
------- ------- -------
Total $12,095 $15,096 $11,815
======= ======= =======
Depreciation, depletion
and amortization (a):
Oil and gas $ 3,784 $ 3,238 $ 2,763
Services 62 57 72
------- ------- -------
Total $ 3,846 $ 3,295 $ 2,835
======= ======= =======
Operating income (loss):
Oil and gas $ (582)(b) $ 4,714(b) $ 4,339(b)
Services 342 424 249
General corporate expenses (1,466) (1,372) (999)
------- ------- -------
Total operating income (1,706) 3,766 3,589
Interest expense and other (287) (170) (262)
------- ------- --------
Earnings before income taxes $(1,992) $ 3,596 $ 3,327
======= ======= =======
Identifiable assets (a):
Oil and gas $19,587 $21,917 $18,910
Services 4,362 4,218 2,715
------- ------- -------
Total $23,949 $26,135 $21,625
======= ======= =======
Additions to property and equipment:
Oil and gas $ 5,872 $ 9,671 $ 7,167
Services 45 7 12
------- ------- -------
Total $ 5,917 $ 9,678 $ 7,179
======= ======= =======
(a) 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.
(b) Includes non-cash impairment loss of $3,482,000 in 1998, $2,179,000 in 1997
and $165,000 in 1996.
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 12, 1999 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 2/12/99
- --------------------------- -------
Harry A. Trueblood, Jr.
Chief Operating Officer
Executive Vice President
/s/ Clarence H. Brown and Chief Operating Officer 2/12/99
- --------------------------- -------
Clarence H. Brown
Principal Accounting and Financial Officer
/s/ Ronald H. Beck Vice President 2/12/99
- --------------------------- -------
Ronald H. Beck
Majority of Board of Directors
/s/ Harry A. Trueblood, Jr. Director 2/12/99
- --------------------------- -------
Harry A. Trueblood, Jr.
/s/ Clarence H. Brown Director 2/12/99
- --------------------------- -------
Clarence H. Brown
/s/ J. Samuel Butler Director 2/12/99
- --------------------------- -------
J. Samuel Butler
/s/ William H. Blount, Jr. Director 2/12/99
- --------------------------- -------
William H. Blount, Jr.
72
<PAGE>
Commission File No. 1-9872
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K
ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED NOVEMBER 30, 1998
COLUMBUS ENERGY CORP.
(Exact Name of Registrant)
1660 Lincoln Street
Denver, Colorado 80264
(Address of Principal Executive Office)
EXHIBIT 22
COLUMBUS ENERGY CORP.
SUBSIDIARIES
November 30, 1998
Name Ownership
---- ---------
Columbus Gas Services, Inc. 100%
Columbus Texas, Inc. 100%
Columbus Energy, L.P. (as general partner) 1%
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 Nos. 33- 63336, 33-93156 and 33-25743)
of our report dated February 10, 1999, on our audits of the consolidated
financial statements of Columbus Energy Corp. as of November 30, 1998 and 1997,
and for the years ended November 30, 1998, 1997, and 1996, which report is
included in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Denver, Colorado
February 10, 1999
EXHIBIT 23(b)
(REED W. FERRILL & ASSOCIATES LETTERHEAD)
February 10, 1999
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 January 27, 1999 entitled "Columbus Energy Corp., Reserve and
Revenue Forecast as of November 30, 1998, 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,
1998.
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 10, 1999
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, 1999, entitled "Columbus Energy Corp., Berry R. Cox Field, Estimated
Reserves and Revenues, as of November 30, 1998, 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, 1998.
For and On Behalf of
HUDDLESTON & CO., INC.
\s\Peter D. Huddleston
--------------------------
Peter D. Huddleston, P.E.
President
<TABLE> <S> <C>
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The consolidated balance sheet as of November 30, 1998 and the consolidated
statement of income for the year ended november 30, 1998.
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<NAME> Columbus Energy Corp.
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