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, 1999 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 80264
Denver, Colorado ----------
- ---------------------------------------- (Zip code)
(Address of principal executive offices)
Registrant's telephone number, including area code:
(303) 861-5252
Securities registered pursuant to
Section 12(b) of the Act:
Name of each Exchange on
Title of each class which registered
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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, 2000 is $16,848,000.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of January 31, 2000
Outstanding at
Class January 31, 2000
----- ----------------
Common Stock, ($.20 par value) 3,762,374 shares
DOCUMENTS INCORPORATED BY REFERENCE
Columbus Energy Corp. definitive proxy statement to be filed no later than
120 days after the end of the fiscal year covered by this report, is
incorporated by reference into Part III.
<PAGE>
ANNUAL REPORT (S.E.C. FORM 10-K)
INDEX
Securities and Exchange Commission
Item Number and Description
PART I
Page
----
Item 1. Business............................................................3
Item 2. Properties - Oil and Gas Operations ............................... 4
Item 3. Legal Proceedings..................................................22
Item 4. Submission of Matters to a
Vote of Security Holders....................................23
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters.............................24
Item 6. Selected Financial Data............................................25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.........................26
Item 7A. Quantitative and Qualitative Disclosure About Market Risk .........41
Item 8. Financial Statements and Supplementary Data........................42
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......................42
PART III
Item 10. Directors and Executive Officers
of the Registrant...........................................43
Item 11. Executive Compensation.............................................43
Item 12. Security Ownership of Certain Beneficial
Owners and Management.......................................43
Item 13. Certain Relationships and
Related Transactions........................................43
PART IV AND SIGNATURES
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K...........................44
Signatures.........................................................75
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 also a wholly-owned subsidiary but became a separate
publicly-owned entity when it was spun-off via a rights offering by Columbus to
its shareholders. The term "Company" or "EGY" as used herein includes Columbus
and its subsidiaries.
The Company currently has 31 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.
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 stock 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.
3
<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, 1999, 1998 and 1997.
PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
1999 1998 1997
------------------- ----------------- -----------------
Oil Gas Oil Gas Oil Gas
MBbl Mmcf MBbl Mmcf MBbl Mmcf
---- ---- ---- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year 960 22,463 1,805 18,520 1,643 18,665
Revisions of previous
estimates 399 (1,405) (713) 767 (127) 226
Purchase of reserves - - 1 320 - -
Extensions and discoveries 68 726 88 6,355 538 5,066
Production (169) (3,201) (221) (3,499) (249) (3,370)
Sale of reserves - - - - - (2,067)
------ ------ ----- ------ ----- ------
End of year 1,258 18,583 960 22,463 1,805 18,520
====== ====== ===== ====== ===== ======
Proved developed reserves:
Beginning of year 762 20,674 1,333 16,122 1,211 15,758
====== ====== ===== ====== ===== ======
End of year 925 14,748 762 20,674 1,333 16,122
====== ====== ===== ====== ===== ======
</TABLE>
Proved Developed Producing Reserves
As of November 30, 1999, Columbus has approximately 815,000 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
Montana and Texas account for over 98%, and Texas alone 77%, 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 11.0 billion cubic feet of
proved developed producing gas reserves. Texas properties account for 95% 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.
4
<PAGE>
Proved Developed Non-Producing Reserves
The reserves in this category are located in the states of Texas, Louisiana
and Montana. 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 110,000 barrels of oil, or 9% of its
total proved oil reserves, and 3.7 billion cubic feet of natural gas, or 20% of
its total proved natural gas reserves.
Proved Undeveloped Reserves
Columbus' proved undeveloped reserves were approximately 333,000 barrels
and 3.8 billion cubic feet of natural gas. Almost all of the oil reserves in
this category are in Montana. All of the proved undeveloped gas reserves are
attributable to undrilled locations offsetting production in Webb, Zapata,
Harris and Jim Hogg Counties, Texas and Montana.
These reserves are expected to either be developed during 2000 or in future
when there is some stabilization of oil prices at levels which will yield a
satisfactory rate of return on investment without fear of another roller coaster
price fallout.
5
<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)
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Future oil and gas revenues $ 74,284 $53,271 $ 79,381
Future cost:
Production cost (24,031) (13,688) (21,856)
Development cost (4,811) (2,638) (5,401)
Future income taxes (10,504) (6,325) (11,531)
-------- ------- --------
Future net cash flows 34,938 30,620 40,593
Discount at 10% (11,229) (8,691) (10,422)
-------- ------- --------
Standardized measure of discounted future net
cash flows $ 23,709 $21,929 $ 30,171
======== ======= ========
</TABLE>
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
FOR THE THREE YEARS ENDED NOVEMBER 30, 1999
(thousands of dollars)
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Balance, beginning of year $21,929 $30,171 $ 38,160
Sale of oil and gas net of production costs (7,081) (7,397) (10,708)
Net changes in prices and production costs 9,801 (12,034) (10,502)
Purchase of reserves - 310 -
Sale of reserves - - (1.320)
Extensions, discoveries and other additions 1,150 6,896 9,660
Revisions to previous estimates 1,346 (3,406) (710)
Previously estimated development costs
incurred during the period 268 586 1,089
Changes in development costs (1,945) 2,066 229
Accretion of discount 2,599 3,730 4,653
Other (1,951) (2,066) (1,620)
Change in future income taxes (2,407) 3,073 1,240
------- ------- -------
Net increase (decrease) 1,780 (8,242) (7,989)
------- ------- -------
Balance, end of year $23,709 $21,929 $30,171
======= ======= =======
</TABLE>
6
<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, 1999, 1998 and
1997. 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
$30,173,000 in 1999, $25,986,000 in 1998, and $37,301,000 in 1997. 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, 1999 the crude oil price
(including natural gas liquids) was $23.48 per barrel and the natural gas price
was $2.41 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.
7
<PAGE>
Both 1999 and 1998 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, 1999, 1998 and 1997. The reports for 1998 and 1997 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
----------------------------------------
1999 1998 1997
---- ---- ----
Oil-barrels 169,000 221,000 249,000
Gas-Mmcf 3,201 3,499 3,370
During the fiscal year 1999, 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
1998. This data was reported on a gross operated basis inclusive of royalty
interest and, therefore, does not compare with Columbus' net reserves reported
for 1998.
Average price and cost per unit of production for the past three fiscal
years are as follows:
Fiscal Year
-----------------------------------------
1999 1998 1997
------ ---- ----
Average sales price:
per barrel of oil $16.63 $13.22 $19.62
per Mcf of gas $ 2.28 $ 2.18 $ 2.65
Average production cost per
equivalent barrel $ 4.18 $ 4.00 $ 3.83
Natural gas is converted to oil at the ratio of six Mcf of natural gas to
one barrel of oil. Production costs for fiscal years 1999, 1998 and 1997 include
production taxes.
8
<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, 1999 Gross Net
- ----------------- ---------------- ----------------
Oil Gas Oil Gas
--- --- --- ---
Wells 80 169 21 21
Acres 33,788 9,845
Undeveloped Properties
The following table sets forth the Company's ownership in undeveloped
properties:
November 30, 1999 Gross Acres Net Acres
- ------------------ ----------- ---------
Louisiana 16,047 1,561
Montana 11,223 6,759
New Mexico 840 630
North Dakota 1,659 277
Oklahoma 1,280 640
Texas 7,460 3,682
------ ------
Total Undeveloped Properties 38,509 13,549
====== ======
9
<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,
------------------------------------------------------------
1999 1998 1997
--------------- --------------- ----------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY
Wells Drilled:
Oil 2 1.34 2 1.10 2 1.45
Gas 1 .54 3 1.69 1 .37
Dry 4 2.38 2 .92 1 .34
DEVELOPMENT
Wells Drilled:
Oil 0 0 1 .67 4 1.91
Gas 7 1.63 8 1.06 18 2.71
Dry 2 .15 4 1.23 3 .65
TOTAL
Wells Drilled:
Oil 2 1.34 3 1.77 6 3.36
Gas 8 2.17 11 2.75 19 3.08
Dry 6 2.53 6 2.15 4 .99
-- ---- --- ---- -- ----
Total 16 6.04 20 6.67 29 7.43
== ==== === ==== == ====
</TABLE>
10
<PAGE>
Current Activities
During the fourth quarter of fiscal 1999 and subsequent thereto, there
was a flurry of drilling and completion activity involving the El Squared
prospect in Bee County. This was primarily related to the impending expiration
of the primary term of the Fred Long lease which represented over 40% of the
approximate 5,700 acres of leaseholds in that prospect block. This lease could
be extended over the primary term with two alternatives available. One of these
required payment to the royalty owner of approximately $500,000 of lease bonus
for a two-year lease extension agreement which also required modifications to
the base lease with some fairly significant changes in the size of and the
manner in which drilling units could be created or pooled. The other alternative
available was to have drilling operations under way over the primary term of the
lease or have a well completing within 60 days of expiration of the primary term
of the lease, or both.
Columbus, as operator for its own account as well as on behalf of
participants, determined to have both circumstances in existence by essentially
utilizing the bonus money equivalent to commence drilling a deviated wellbore
toward an upper Massive objective after cutting a window in the casing in the
Long #3 and be drilling over the January 7, 2000 lease expiration date.
Fortunately, there was already a completion attempt under way at the Long #4
which met the within 60 days of the lease expiration requirement. During the
last week in December 1999 and early in January of 2000, management initially
tried to establish commercial production from a lower Massive section at
approximately 13,000 feet as well as in a stray sand in the Massive silt
interval at approximately 12,300 feet. It was assumed that if those zones proved
to be unsuccessful, the upper Massive Sand at approximately 12,000 feet, which
had an excellent electric log in that interval, could be completed as a gas
producer. However, a continuous drilling program would be necessary with the
commencement of a new well every 60 days following completion of a preceding
well in order to keep the lease in force. This provision was expected to provide
a sufficient period of time to allow the group to develop the anticipated
reserves in fault block "B" in the upper and middle Wilcox Sands. Such a program
would not maintain the deep Wilcox Reagan Sands under lease without drilling a
wellbore to that depth, but the group was unwilling to take that route because
of the expense and the risk associated therewith. Based on 3-D seismic
interpretation, only one potential Reagan structure was being given up under the
Long lease and those rights were owned under the remaining acreage.
11
<PAGE>
Management was able to meet the critical path logistics necessary to keep
the lease in force but then had to suffer severe disappointment from the results
of those extraordinary efforts. As explained in a Special Interim Report to
Shareholders on January 14, 2000, the lower Massive zone was fairly tight and
yielded only about 100,000 cubic feet per day flow rate although it exhibited an
extremely high shut-in bottom hole pressure of approximately 10,000 psig.
Management was not confident that a fracture stimulation of that sand would
yield a completion with sufficient flow rates to justify postponing completion
of the upper Massive zone and leaving it shut-in behind unperforated casing. A
dual completion was not practical. Furthermore, a small amount of water with
limited gas had been added from the zone at 12,300 feet after being perforated.
This effectively eliminated any further consideration of the basal sand being
fracture stimulated without encountering considerable wellbore logistical
problems to isolate that lower zone from the 12,300-foot zone.
As a consequence, completion efforts were moved uphole where we fully
expected an excellent flow of gas from the upper Massive zone. This belief was
supported by good sand in the mud samples along with a reasonable show of gas
plus corroborating electric logs of the interval. The latter had been
interpreted by various service company experts, our consultants, and Columbus'
own personnel as being gas productive with a reasonably high flow rate
anticipated. This confidence was further supported by log calculations which
were made using available known resistivities from water samples obtained from
an upper Massive Sand interval in the initial deviated hole drilled from the
Long #3 which had flowed gas and water. It was over 300 feet down structure from
this Long #4 sand but was in a separate fault block. To the absolute
astonishment of all concerned, this upper Massive Sand inexplicably yielded
formation water with only a very limited amount of accompanying gas. In fact, a
significant hourly rate was swabbed from 25 feet of perforations from within a
gross sand interval of 90 feet so the zone was permeable but definitely wet. To
date, no one has a solid explanation for these results. Admittedly, the water in
this interval was a bit fresher and this isolated fault block was probably
completely sealed, but this is not a satisfactory explanation. So confident that
commercial gas production would be found by every person involved, the Company
had already installed a gathering line in order to connect the well and commence
sales immediately. Unfortunately, surprises such as this have plagued
explorationists since the first U.S. commercial oil discovery in 1859. It is a
part of the business not understood by most people outside of the industry and
is painful to those within.
As soon as it was established that the upper Massive Sand was water
productive, management also shut down drilling operations at the Long #3
sidetrack hole. However, by the time this could be done, the wellbore was
already at a measured depth of 10,800 feet and was over 150 feet away from the
original wellbore and at a 20 degree angle. Management did weigh the possibility
of continuing drilling operations at the Long #3 until it reached its objective
since it would have required only a few days and because this sand would be in a
different fault block. To support the notion that this might make a difference,
the sand in the initial Long #3 deviated wellbore had yielded considerably more
gas than the Long #4 despite being over 300 feet structurally lower. However,
12
<PAGE>
the likelihood of finding a water free completion updip in the Long #3 fault
block carried too much risk. It was believed those same funds could be used to
further develop additional gas reserves from the Slick Sands which are known
producers in this "B" fault block area.
Because of the Long #4 results, two other identified upper Massive
locations were scrapped and it was determined to farmout about 1,000 acres of
leaseholds within the "A" fault block area on the east side of the El Squared
acreage block. This farmout will require a test of a sizable Massive structure
identified by 3-D seismic which will be followed by a working interest back-in
after payout to Columbus, et al. In addition, there are at least three
Slick/Luling Sand upper Wilcox structures previously identified on the El
Squared acreage which can be drilled during fiscal 2000. While these structures
are not quite so romantic as Massive prospects, they do offer potential reserves
at each structure of 5 to 10 billion cubic feet plus associated condensate with
considerably lower costs to develop.
As fiscal 1999 came to a close, Columbus had no rigs actively drilling at
any of its other key areas as the focus and funds had been dedicated to El
Squared activity. There were two wells in the Laredo area that had been drilled
which for tax reasons were awaiting completion until after January 1, 2000.
These were being carried as "in progress" at year end. A few proved undeveloped
locations have been identified for drilling in the Laredo area during fiscal
2000 and more should be forthcoming.
A more detailed description related to recent activities as segregated by
Columbus' primary areas of operations follows:
South Texas - Laredo Area
This continues to be the most important operational area where 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 several years in the area near Laredo, Columbus has, for a
good portion of each year, had at least one rig drilling infill, extension, and
new fault block locations which had been identified by a 3-D seismic program
conducted in 1994-95. During fiscal 1999, only five (1.01 net) gas wells were
drilled and completed successfully. In addition, one (.06 net) well was drilled
which resulted in a dry hole. The total number of wells was somewhat reduced
from past drilling programs of 10 wells in fiscal 1998, 18 in fiscal 1997, and
12 in fiscal 1996.
13
<PAGE>
In the B. R. Cox field, Columbus continued to postpone all workovers,
recompletions, or new drilling because of the failure of the largest working
interest owner's willingness or capability to advance their share of the funds
required to do the work. Even worse, they would not agree to go non-consent and
suffer penalties provided for in the Operating Agreement so we have been
stalemated for years. Continued frustration with this "do nothing" stance
appears about to be alleviated as that company recently agreed to sell the
balance of its properties in this field to another operator. At least now the
working interest holders should be able to jointly perform some much needed
workovers to reestablish commercial production at several shut-in wells. Also,
the group will consider drilling at least one or more wells during fiscal 2000.
El Squared Prospect - Bee County, Texas
This prospect area is one for which recent drilling activities were
discussed in detail above and had previously been described in earlier reports
and news releases as one of the most exciting areas for potential reserve
accumulation since Columbus' Sralla Road discovery east of Houston in 1990.
Currently, leaseholds approximate 5,700 acres in size of which all have been
shot with 3- D seismic and Columbus currently owns a 55% working interest (42%
NRI) while three of its drilling associates own working interests which total
20%. An energy company which originated the prospect owns the remaining 25% and
its principal owner is also the mineral owner of the prospect's largest
individual lease which is almost 2,500 acres in size. As indicated, there was a
flurry of calendar year end activity because its expiration date was January 7,
2000. Two successful Slick Sand wells have been completed thereon with each of
the wells being inside 320-acre units which overlap so approximately 450 plus
acres out of the almost 2,500 acres will be held by production. The balance will
probably be allowed to expire because of the lack of a continuous drilling
program. Most of this leasehold cost was wiped out by exploratory expense
charges in fiscal 1999 as it appears the Massive zones of the Wilcox have pretty
much been condemned under the Long lease. Shallower sand development location(s)
are within these producing units for the most part.
Only one working interest well (0.54 net), the Long #2, was actually
completed during fiscal 1999 as lower Slick producer while the other two wells
were in an "in progress" status at year end. These were the Long #3 (0.75 net
WI) and the Long #4 (0.90 net WI) which were subsequently determined to be
unsuccessful exploratory wells as previously discussed following recovery of
water in the upper Massive in the Long #4 and cessation of drilling at the Long
#3. These cased wellbores are being kept intact for the present in case they
might be usable for some other purpose.
14
<PAGE>
Several leases adjacent to the Long lease have now had their
attractiveness eliminated by the Massive Sand being condemned in this "B" fault
block. Some of those remaining leases have possibilities of being productive in
the Slick/Luling zones of the upper Wilcox and three drillable structures have
been identified thus far on remaining acreage in the prospect.
As mentioned in Current Activities, the proposed farmout which is about
to be offered to industry is a separate leasehold block of 1,021 acres. The
farmee would acquire 100% of this acreage and related seismic for $160,000 which
approximates the actual cost thereof. An initial test well will be required to
be drilled to a depth of 12,000 feet to test an upper Massive sand which
underlies the "A" fault block and a 352-acre drilling unit has been defined for
that purpose. Also, a lower Massive sand structure whose apex lies to the west
of this initial test well site is essentially located entirely within this
1,021-acre leasehold block should the farmee desire to drill another wellbore at
some future date. Such a test well is not a requirement under the proposed
farmout agreement. At such time as the farmee has recovered all of its costs of
drilling and completing the initial test well, Columbus, et al, will back in for
a 33 1/3% working interest in that drilling unit assuming a successful
completion. Because this wildcat location is in an entirely separate fault block
and a separate structure on the basinward side of the "A" fault, it is unrelated
to the Long #4. This test well will be the second deep test ever to be drilled
in this fault block and its structural location is over 300 feet high to the
prior well which was drilled in 1977. That initial well had excellent shows of
gas in a sand which appears to be the upper Massive but that zone was never
perforated and tested because the hole was junked while trying to run production
liner. It is expected this farmout well will be drilled during the next few
months assuming its terms can be negotiated successfully early in fiscal 2000.
In addition to the previously planned tests during fiscal 2000 of
untested Slick/Luling structures on the remaining leaseholds which are still
intact, the structure on which the Long #1 and #2 wells have been completed will
require the drilling of a Long #5 wellbore in order to timely and adequately
drain the main Slick sand and the lower Slick sand reservoirs. This well site
should not only find those two reservoirs at structural positions of 30 feet to
45 feet high to Long #1 but would permit the upper portion of the lower Slick
sand to be drained as it was faulted out in the Long #2. Also, the main Slick
sand that produced initially in the Long #1 was shut-off by a through tubing
bridge plug and needs to be returned to production very soon rather than wait
until upper Slick reserves have been depleted in the Long #1. Particularly
appealing is the fact the structurally favorable Long #5 location should recover
"chimney" gas reserves for that zone as well as the lower Slick. Both producing
zones would probably be produced through separate strings of tubing in this
single wellbore to facilitate workover operations when required. A combination
of the present worth value improvement of accelerating recovery of the gas
reserves related to both reservoirs plus their higher structural locations that
should recover reserves which might otherwise be lost more than justifies the
drilling of this Long #5 location. It was previously proposed but then postponed
because of the flurry of year end activity surrounding the testing of the
Massive structures on the Long lease.
15
<PAGE>
Sralla Road Field Area - Harris County, Texas
During fiscal 1999, there was participation in two wells drilled on the
south end of this field. One of those wells was in the form of an overriding
royalty (0.0022 NRI) in a successful gas well drilled by another operator.
Because of the relatively minor amount of acreage that could be contributed to
form the 160-acre drilling unit and the wellbore would have to be directionally
drilled with no cinch completion, that acreage was farmed out and an overriding
royalty retained. A second well, the Johnson/Peace #1, was drilled by that same
operator at the southwesternmost end of the field. This proved to be an
expensive dry hole as unfortunately the operator attempted to complete same.
Columbus contributed its limited acreage owned to this 160-acre drilling unit
and fortunately participated for only a 0.086 net working interest. This unit
offset to the south Columbus' Jones #1 oil well discovery that was announced in
fiscal 1998. That well was placed on production flowing 200 barrels of oil per
day in June 1999 after completion of a gas gathering system through a densely
populated area. Columbus owns 19% working interest in the Jones #1 well and 5%
of the gathering system. Apparently there is a cross fault between the Jones #1
well and the Johnson/Peace #1 dry hole which accounts for the latter being water
bearing. This is the first indication of water being present in the Jackson sand
in the Sralla Road West Jackson sand field and most probably signals the
southwestern extremity of the field has been found.
The Sralla Road Field area has been a very important asset to Columbus
throughout the last decade. This was primarily because of a relatively small,
but very prolific, Vicksburg oil field which generated the necessary cash flow
which allowed the Company to take risks in extending both the initial Jackson
sand field on the downthrown side of the "B" fault as well as on the upside
thereof. The very thin (3' to 6') sand thickness found in both Jackson fields
required the wells to be drilled on 160 acre spacing to make any economic sense
when the costs and risks involved were weighed. There was little room for any
dry holes or marginal wells to be drilled yet some were drilled as these fields
were being defined. However, a combination of increased gas prices during the
1990's and the recent recovery of crude oil prices has definitely improved the
outlook for obtaining a decent rate of return on recent investments during the
coming years. Furthermore, without the initial Jackson sand oil discovery having
been completed in only four feet of sand at the Davis Oil Unit #1 in 1988, the
shallower Vicksburg oil discovery at the offset Davis B-1 would never have been
found. One must therefore consider the overall return from the area from every
source so the Jackson sand may claim credit for that discovery. Overall, this
area proved to be very satisfactory from that standpoint and this field has been
Columbus' primary source of field level cash flow for the past ten years.
16
<PAGE>
About 20 miles east of the Sralla Road field, one of the best gas wells
in which the Company owns an interest is located near the famous old Anahuac
field in Chambers County, Texas. This well, the Syphrett Heirs #1, was
discovered in July, 1997 and has sold around 100 million cubic feet of gas each
month since that completion in the Frio 16 sand and is expected to do so for
many years to come. Columbus originally owned a larger working interest but as a
result of certain "back-ins" that interest approximated about 26% working
interest in fiscal 1999. The most recent reserve review indicated that remaining
reserves yet to be recovered approximate 4.92 BCF so it is expected that this
well will yield a very high production rate for several more years.
Williston Basin Area
During the latter part of fiscal 1998 and the first half of fiscal 1999
this mature area of operations suffered from crude oil prices that were so
ridiculously low that many of the wells which had been profitable had to be shut
down as they were essentially being operated for the benefit of royalty owners
and the state and local taxing authorities. They would not cover the operating
expenses primarily because of pump failures as well as the fact that the
principal producing horizons -- the Ordivician Red River formation and the
Mississippian Mission Canyon formation -- produce water with the crude oil
almost from the beginning of each well's productive life which becomes even a
greater factor as the reservoirs approach the latter stages of their economic
life. During fiscal 1998, a sizeable reduction was recognized for this area for
both the proved producing and proved undeveloped crude oil reserves with
essentially all undeveloped locations being eliminated as marginal or
uneconomic. Also, the potential structures that had been identified by a 3-D
Seismic program were eliminated from further consideration as warranting an
exploratory test well. A general provision was made during both 1998 and 1999 in
the form of an impairment for undeveloped acreage that probably would not
justify a test before expiration of the primary term of the lease.
When crude oil prices began to recover toward mid-year 1999, an attempt
was made to resume operations and all of the wells that had been shut-in. Not
unexpectedly, several of the wells showed a reduced productivity of oil as a
result of the shut-in period. In the instance of two Red River wells, the water
percentage had increased to 100% or to such a high percentage as to be
uneconomic. Fortunately, two of these wells, the Ullman #1 and the Young Heirs
#4, had porous zones in the shallower Duperow formation which offered promise of
17
<PAGE>
being productive of commercial rates of oil and were successfully recompleted in
this uphole zone as oil discoveries. While the initial production began at
higher rates, both of these wells leveled off to about 50 barrels of oil per day
and have settled into what is believed will be the long slow decline which is
customary with the various producing formations in this deeper portion of the
Williston Basin. Most of the wells the Company owns in this area are at least 20
years old while several are over 30 years old and still are producing from the
original zone in which the well was completed. Decline curve history of a
majority of these reservoirs appears to settle at less than 5% per year with
ultimate well life depending more on the integrity of the production casing
against collapse opposite salt sections than on depletion. Also, since there
appears to be evidence of a limited water drive in almost all of these fields.
Although the production rates of these newly completed discoveries in the
Duperow are modest, Columbus owns a substantial 63.7% working interest in the
Ullman #2 and a 70.3% working interest in the Young Heirs #4 and their economic
well life expectancy at this time could be in the 20 year range barring
unforeseen mechanical problems.
By the end of fiscal 1999, the price of crude oil had recovered to a
high enough level and for a sufficient length of time for some of the previously
dropped reserves for proved undeveloped locations to be restored. Also, the
economic well life of several wells was extended thereby adding to the proved
developed producing reserves for those wells which had produced during the two
years of low prices as well as for those which had successfully been placed back
on production because water production had not rendered them uneconomic or had
not been permanently abandoned or recompleted. If crude prices would eventually
stabilize in the $25 per barrel range, management would feel more comfortable
that a reasonable rate of return could be realized and the proved undeveloped
locations could then be drilled. There is sufficient available forecasted cash
flow in excess of preliminary budget for the coming year to enable Columbus to
add one or more Red River wells and/or several of the shallower Mission Canyon
locations.
18
<PAGE>
Titles
The Company is confident that it has satisfactory title to its producing
properties which are held pursuant to leases from third parties and have been
examined on several occasions to determine their suitability to serve as
collateral for bank loans. Oil and gas interests are subject to customary
interest and burdens, including overriding royalties and operating agreements.
Titles to the Company's properties may also be subject to liens incident to
operating agreements and minor encumbrances, easements and restrictions.
As is customary in the oil and gas industry, the Company does not
regularly investigate titles to oil and gas leases when acquiring undeveloped
acreage. Title is typically examined before any drilling or development is
undertaken by checking the county and various governmental records to determine
the ownership of the land and the validity of the oil and gas leases on which
drilling is to take place. The methods of title examination adopted by the
Company are reasonably calculated, in the opinion of the Company, to insure that
production from its properties, if obtained, will be readily salable for the
account of the Company. As stated above, certain of the Company's producing
properties have been subject to independent title investigations as a
consequence of bank loans obtained and have been accepted for such purposes.
Insofar as is known to the Company, there is no material litigation pending or
threatened pertaining to its proved acreage.
The producing and non-producing acreages are subject to customary
royalty interests, liens for current taxes, and other burdens, none of which, in
the opinion of the Company, materially interfere with the use of or adversely
affect the value of such properties.
Competition, Marketing and Customers
Competition and Marketing. The oil and gas industry is highly
competitive. Major oil and gas companies, independent producers with public
drilling and production purchase programs and individual producers and operators
are active bidders for desirable oil and gas properties as well as for the
equipment and labor required to operate such properties. Many competitors have
financial resources, staffs and facilities substantially greater than those of
the Company. A ready market for the oil and gas production is, to a limited
extent, dependent upon the cost and availability of alternative fuels as well as
upon the level of consumer demand and domestic production of oil and gas; the
amount 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.
19
<PAGE>
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 wellhead 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, 1999, 1998 and 1997, are set forth in Note 3 to Notes to the
Consolidated Financial Statements. In the opinion of management, a loss of a
customer has not to date, and should not in the future, materially affect the
Company since the nature of the oil and gas industry is such that alternative
purchasers are normally available on very short notice.
Government Regulations
The development, production and sale of oil and gas is subject to
various federal, state and local governmental regulations. In general,
regulatory agencies are empowered to make and enforce regulations to prevent
waste of oil and gas, to protect the correlative rights and opportunities to
produce oil and gas between owners of a common reservoir, and to protect the
environment. Matters subject to regulation include, but are not limited to,
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties,
taxation and environmental protection. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and gas wells below actual production capacity in order to
conserve supplies of oil and gas.
20
<PAGE>
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.
21
<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.
Following a rehearing with minimum modification, it was subsequently reissued as
FERC Order No. 636A which has led to much more competitive markets. It raised
questions about whether gathering systems of interstate pipelines can be sold
off and totally escape regulation but in more recent hearings FERC has failed to
resolve this issue satisfactorily by suggesting this is a matter for regulatory
authorities in various local jurisdictions.
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 55th District Court of
Harris County, Texas. The plaintiffs are parties to a September 1994 settlement
agreement that provided for the conveyance of overriding royalty interests in
leases acquired by Columbus in certain portions of Harris County. Plaintiffs
claim Columbus is obligated under the settlement agreement to acquire all leases
available within a described portion of Harris County and that Columbus has
failed to develop those leases as a reasonably prudent operator. Plaintiffs are
claiming damages based upon their alleged right to a 3% overriding royalty
interest in leases taken and drilled by third parties within the described area.
Discovery is ongoing. Columbus denies all allegations of failure to develop and
instructed counsel to vigorously defend this lawsuit. The parties are set for
mediation on April 11, 2000 and for trial on May 22, 2000.
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.
22
<PAGE>
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1999, no matters were submitted to a vote
of security holders.
23
<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)
------- ------
2000:
December 1, 1999 through
January 31, 2000 $ 5.75 $ 5.50
1999:
First quarter $ 6.75 $ 6.125
Second quarter 6.25 5.50
Third quarter 6.125 5.68
Fourth quarter 6.00 5.25
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
(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 31, 2000 the reported closing sales price of Columbus
common stock was $5.625 per share.
As of November 30, 1999, there were approximately 420 holders of record
of Columbus' common stock and an estimated 1,000 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.
24
<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, 1999, 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,
-------------------------------------------------------------------------------
1999 1998 1997 1996 1995(a)
---- ---- ---- ---- ----
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Operating data:
Revenues $11,500 $ 12,094 $15,156 $11,815 $ 9,400
Loss on asset disposition,
impairment of long-lived
properties and abandonments (973) (3,482) (2,179) (165) (3,055)
Net earnings (loss) (1,215) (1,235) 2,167 2,098 (1,495)
======= ======== ======= ======= =======
Earnings (loss) per
share(b):
Basic $ (.31) $ (.29) $ .50 $ .50 $ (.35)
======= ======== ======= ======= =======
Diluted $ (.31) $ (.29) $ .49 $ .49 $ (.35)
======= ======== ======= ======= =======
Weighted average number of
common and common equivalent
shares outstanding(b):
Basic 3,898 4,194 4,299 4,211 4,321
======= ======== ======= ======= =======
Diluted 3,898 4,194 4,392 4,259 4,321
======= ======== ======= ======= =======
Cash flow data(d):
Cash from operating activities $ 3,258 $ 6,258 $ 8,638 $ 5,638 $ 3,929
Cash used in investing activities $(2,336) $ (6,717) $(7,294) $(6,320) $ (119)
Cash provided by (used in)
financing activities(c) $(1,075) $ 605 $ (883) $ 664 $(4,223)
Cash flow before changes in
operating assets and liabilities $ 3,027 $ 5,470 $ 9,132 $ 6,340 $ 3,920
Discretionary cash flow $ 5,770 $ 6,192 $ 9,672 $ 6,658 $ 4,096
Balance sheet data:
Total assets $22,530 $ 23,949 $26,135 $21,625 $18,321
Long-term debt, excluding
current maturities - bank debt $ 5,500 $ 4,900 $ 2,200 $ 2,200 $ 1,600
Stockholders' equity $12,798 $ 15,264 $17,958 $16,225 $13,186
</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".
25
<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
By mid-1999 crude oil prices had begun to recover after two years of dismal
prices. Natural gas prices also had a similar recovery from lower prices during
the winter of 1998/1999. The Company's natural gas prices averaged 5% higher
than in 1998 while annual production was down 9% compared to 1998 for reasons
discussed later. Improved prices did not fully offset the 24% decline in crude
oil production which resulted in lower revenues. Fiscal 1999 had substantially
higher exploration expenses but lower impairment charges so that the 1999 net
loss approximated that of 1998. Such charges in 1999 totaled $4,044,000 which,
after being tax effected, reduced net earnings by $2,790,000, or $0.72 per share
which thereby created a net loss of $1,215,000, or $0.31 per share. During 1998
exploration charges of $722,000 and impairment charges of $3,482,000 were
primarily responsible for the net loss of $1,235,000, or $0.29 per share. Low
crude oil prices during the 1998 fiscal year contributed to the impairments and
essentially eliminated drilling for crude oil production and reserves. Average
shares outstanding for fiscal 1999 were only 3,898,000 compared to 4,194,000
last year. Discretionary Cash Flow in 1999 of $5,770,000 was 7% lower than
1998's because of lower gross revenues and oil and gas sales.
As of the end of 1999, shareholders' equity decreased to $12,798,000
compared to $15,264,000 at November 30, 1998 as a result of the exploration and
impairment charges along with repurchases of treasury shares. Positive working
capital was $1,169,000 at year end which, when combined with the Company's
anticipated cash flow for 2000, should provide sufficient funds for the capital
expenditure program during fiscal 2000 which will continue to be directed toward
onshore exploratory drilling in the lower Gulf Coast area including activity on
existing El Squared prospect leaseholds. 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 unforeseen capital expenditures arise
during 2000 as a result of exploratory success.
26
<PAGE>
Generally accepted accounting principles ("GAAP") require cash flows from
operating activities to be determined after giving effect to working capital
changes. Accordingly, GAAP's net cash provided from operating activities has
fluctuated widely from $3,300,000 to $8,600,000 during the last three years but,
when coupled with use of the Company's credit facility, still 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.
As regularly noted in prior reports, management places greater reliance upon
an important alternative method of computing cash flow which is generally known
as Discretionary Cash Flow ("DCF"). DCF is not in accordance with GAAP but is
commonly used in the industry as this method calculates cash flow before working
capital changes or deduction of exploration expenses since the latter can be
increased or decreased at management's discretion. DCF is often used by
successful efforts companies to compare their cash flow results with those
independent energy companies who use the full cost accounting method where
exploration expenses are capitalized and do not immediately adversely affect
either operating cash flow or net earnings. Columbus' DCF for 1999 was
$5,770,000 which compared to 1998's $6,192,000 when more shares were
outstanding. DCF is calculated without debt retirement being considered but in
Columbus' case this does not matter as current bank debt requires no principal
payments before August 1, 2001. Interest expense is always deducted before
arriving at DCF.
Management notes in each of its public filings and reports its strong
exception to the Statement of Financial Accounting Standards No. 95 as it
applies to Columbus which directs that operating cash flow must only be
determined after consideration of working capital changes. Management believes
such a requirement by GAAP ignores entirely the significant impact that the
timing of income received for, and expenses incurred on behalf of, third party
owners in properties may have on working capital. This is particularly
significant where Columbus owns only a small working interest but is the
operator.
Neither DCF nor operating cash flow before working capital changes is
allowed to be substituted for net income or for cash available from operations
as defined by GAAP. Furthermore, currently reported cash flows, however defined,
are not necessarily indicative that there will be sufficient funds for all
future cash requirements. For 1999 and 1997 GAAP cash flow was lower than DCF
and for 1998 it was the opposite.
27
<PAGE>
At the present time the Company has partially hedged its crude oil prices.
Therefore, the Company's natural gas revenues are fully exposed and a portion of
its crude oil revenues are exposed to risk of very low prices such as existed
during fiscal 1998 and 1999's first half.
Columbus periodically hedges both natural gas and crude oil prices by
entering into "swaps". The swap is 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. There was no hedging activity in
fiscal 1998. The following table shows the results of these swaps:
<TABLE>
<CAPTION>
Increase (decrease) in
oil and gas revenues
Volume ----------------------
Description per mo. Period 1999 1997
- ----------- ------- ------ ---- ----
<S> <C> <C> <C> <C>
(Mmbtu or bbl)
Natural Gas
- -----------
$2.20/Mmbtu 60,000 3/97-10/97 $(86,400)
Crude Oil
- ---------
Collar with $17.50/
bbl floor and
$22.25/bbl ceiling 7,500 9/99- 8/00 $(34,000)
$21.17/bbl 10,000 11/96-10/97 $ 8,900
$17.25/bbl with
$19.50/bbl cap 10,000 1/96-12/96 $(22,500)
</TABLE>
The Company's natural gas and crude oil swaps are considered financial
instruments with off-balance sheet risk which are entered into in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those instruments involved, to varying degrees,
elements of market and credit risk in excess of the amount recognized in the
balance sheets.
The Company had a crude oil hedge outstanding as of November 30, 1999 by
using a costless "collar" on 7,500 barrels per month for the 12 months from
September 1, 1999 through August 31, 2000. This "collar" is settled monthly
against the calendar monthly average price on the NYMEX with a $17.50 per barrel
floor and $22.25 per barrel ceiling. For any average price below or above those
prices Columbus receives or pays the difference which increases or reduces oil
revenues each month in which this occurs. For the two months of December, 1999
and January, 2000, oil sales would have been $65,000 higher if this hedge had
not been in place because oil prices exceeded the $22.25 ceiling price. For the
remaining period of February through August 2000 using the prevailing price as
of January 31, 2000 for each of the months, the settlement value the Company
would owe is $158,000 which would also reduce crude oil sales.
28
<PAGE>
Columbus had outstanding borrowings of $5,500,000 as of November 30, 1999
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 1999, the ratio of
net long-term debt (debt less working capital) to shareholders' equity was 0.34
and to total assets was 0.19. The outstanding debt used a LIBOR option with an
average interest rate of 7.0%. Subsequent to year end through January 31, 2000,
the debt was increased by $200,000 to $5,700,000. 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.
For the Company's floating rate debt, interest rate changes generally do not
affect the fair market value but do impact future results of operations and cash
flows, assuming other factors are held constant. The carrying amount of the
Company's debt approximates its fair value.
Working capital at 1999 year end remained positive at $1,169,000 compared
to $1,556,000 at November 30, 1998. This was achieved despite capital
expenditures of $2,153,000 for additions to oil and gas properties along with
record exploration expenses plus purchase 300,538 shares of treasury stock for
$1,836,000 during the year.
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:
Number of Shares
Fiscal year --------------------------- Average
repurchased As purchased Restated* price*
----------- ------------ --------- -------
1997 158,000 197,863 $6.92
1998 352,750 357,715 $7.07
1999 300,538 300,538 $6.08
*Restated for stock split and stock dividends
As of November 30, 1999 a total of 73,384 shares remained to be purchased
from the most recent authorizations to repurchase shares at a price not to
exceed $6.00 per share. As of January 31, 2000, 45,000 of those shares have
subsequently been acquired at an average price of $5.61 per share.
During 1999, capital expenditures actually incurred for oil and gas
properties totaled $2,153,000 (excludes costs of exploratory dry holes included
in exploration expense) which amount differs from the capital expenditure shown
in the Consolidated Statement of Cash Flows. The latter also includes cash
payments made during 1999 for 1998 expenditures incurred but not yet paid as of
1998's year end. Similarly, there were expenditures accrued in 1999 that will
not be actually paid until 2000. These were primarily related to the exploratory
program in the Texas Gulf Coast area.
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Impact of the Year 2000 issue. The Year 2000 issue is the result of
computer programs being written using two digits rather than four, or other
methods, to define the applicable year. Computer programs that have
date-sensitive software may recognize a date using "00" as the year 1900 rather
than the year 2000 and could result in a system failure or miscalculations
causing disruptions of operations such as a temporary inability to process
transactions, transmit invoices or engage in similar normal business activities.
The Company upgraded its major system computer software in 1997 to a new
release of a major software vendor that the vendor represented was compliant
with the year 2000. Columbus completed before year-end 1999 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
be vulnerable to other failures and what the impact might be on its operations.
The Company's interest in wells operated by other companies was not
considered to be as important but management attempted to determine if those
companies were ready for the year 2000. The Company uses outside services for
payroll and medical benefits processing and those companies provided updates to
their software that they represented were year 2000 compliant. The Company is
also somewhat dependent upon personal computers as well as certain spreadsheet
and word processing software programs which may not have been year 2000
compliant. Evaluations were made to establish which of those systems were
critical and a few personal computers and software programs were replaced at a
cost of less than $10,000.
The Company also relies on non-information technology systems, such as
office telephones, facsimile machines, air conditioning, heating and elevators
in its leased office space, which may have embedded technology such as micro
controllers and are generally outside of its control to assess or remedy.
As previously disclosed, the major system computer software upgrade
performed in 1997 cost $16,000 and personal computer upgrades cost less than
$10,000. This represented the costs required to meet the Company's goal of being
year 2000 ready for mission-critical systems. The Company did not believe that
any loss of revenue would occur as a result of the year 2000 problem. The
Company did not established a contingency plan because it believed all major
issues had been addressed.
As of the date of this report in the year 2000 the Company has not
experienced any year 2000 failures or problems that have affected its computer
systems, operations, revenues, benefits processing or non-information technology
systems. Should any year 2000 failures occur we will address them at that time.
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Results of Operations
The Company's 1999 gross revenues of $11.5 million were 5% below 1998's
and was attributable to lower sales volumes because higher prices were received
for both natural gas and crude oil. The Company's 1998 gross revenues of $12.1
million were 20% below 1997's primarily because of significantly lower prices.
During 1998 low crude oil prices resulted in over one-half of the Company's
operated wells in the Williston Basin being uneconomic which were either shut
down or operated only a few days each month and this continued during 1999's
first half.
The operating loss in 1999 was almost entirely due to record exploration
expense charges and impairments of $4,044,000 because gross revenues were only
slightly lower than 1998's. Lease operating costs, depreciation and amortization
and general and administrative expenses were all lower. The operating loss of
$1,706,000 in 1998 was a direct result of a significant increase in impairments,
lower revenues due to prices plus higher lease operating expenses and
exploration costs compared with 1997. Operating income of $3,766,000 in 1997
represented an improvement of only 5% over 1996 and excluding the exploratory
charges and impairment provisions, this would have been a 59% improvement.
The 1999 net loss of $1,215,000 was caused by the factors previously
discussed as well as increased interest and litigation expense. 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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Impairments
The 1999 pre-tax, non-cash impairment loss of $973,000 included $503,000
that was recorded during the second quarter with the balance added at year end.
The initial improvement in crude oil prices toward the end of the second quarter
was insufficient at that time to justify restoration of previously written down
proved undeveloped reserves in one of the Williston Basin's cost pools which had
led to that pool's impairment charge equal to a shortfall of $253,000 between
remaining book value of the pool and the current fair market value of its
reserves. Elsewhere, an unexpected influx of water in natural gas wells in the
shallow Heidi property in Jim Wells County, Texas brought about premature
abandonment of producing zones and associated natural gas reserves. This
contributed a pre-tax, non-cash impairment of $250,000 of the mid-year charge.
As of 1999's fiscal year end, an impairment of $270,000 was recorded for
one successful efforts pool in Texas where a significant reduction in total
reserve quantities and future net cash flows became evident due to its
producing/pressure performance. Also, there was a charge of $200,000 for an
anticipated loss in value of undeveloped acreage following exploratory dry holes
at the El Squared project and in Oklahoma.
During fiscal 1998, the 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 had showed signs of recovery on occasions throughout the
year but had again retreated to the lows by year end. This resulted in a
significant reduction for total reserve quantities which are based on the SEC
calculation method using constant prices. Therefore, carrying values of
remaining unamortized costs in several successful efforts pools continued to
exceed resultant undiscounted future net cash flows even if determined using
somewhat higher crude prices than were currently being realized. Several
property pools were 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, which was subsequently 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 further shortened
the economic productive life and reserves of most oil wells. Using a $14 price
over the life of the reserves still required an additional non-cash impairment
for the 1998 fourth quarter of $666,000.
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A $400,000 charge in 1998 which was provided during the first quarter was
for probable loss in value of undeveloped acreage and abandonments of leaseholds
located primarily in Louisiana. This was in addition to $200,000 similarly
reserved in 1997. A Louisiana Austin Chalk horizontal well, the Morrow #23-H,
had reserves originally assigned to a contemplated extension of the then current
downdip lateral. However, those reserves were eliminated by price and
performance which contributed heavily to the first quarter provision. Also,
because of added costs related to the necessary recompletion workover required
to place the updip lateral on production, this operation was deferred. Although
economic at a $14 per barrel crude oil price, such a recompletion was postponed
for a minimum of two more years in anticipation that better prices would
favorably alter the present worth of those reserves. This circumstance also
contributed to the fourth quarter provisions.
The non-cash impairment loss of $243,000 for 1997 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 also chose
to write off as impaired certain small leaseholds within the acreage block where
the possibility of putting together a drilling unit before expiration appeared
rather remote. Also included were certain leaseholds where annual rentals were
already due or about to become due. Those non-cash write downs equaled $251,000
which brought the total impairment provision during the third quarter of 1997 to
$494,000.
As fiscal 1997 ended, it had become apparent that with continued
increasing water cuts, the Morrow #23-1H's oil production rates would probably
be less than the initial potential tests had indicated. Accordingly, 1997's
year-end proved reserves attributable to both horizontal legs were reduced which
created additional impairment charges of $1,140,000 related to that Louisiana
well and $84,000 to related leaseholds. Also, a general provision of $200,000
against all undeveloped leaseholds was recorded in anticipation that it was very
likely that additional development probably could not be completed prior to
lease expirations. Also, two oil wells in Oklahoma failed to respond to attempts
to eliminate shifting frac sand from halting production. These were charged with
additional impairment of $260,000 of the total 1997 year end amount even though
the wells had not been abandoned permanently. Another attempt at production is
expected during fiscal 2000 when better crude prices are available which support
drilling horizontally to reduce the shifting frac sand and formation sand
problem since a potentially profitable oil reservoir is believed to exist.
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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
------------ --------------- --------------
1999 vs. 1998
Gas 5 % (9)% (6)%
Oil 26 % (24)% (5)%
1998 vs. 1997
Gas (18)% 4 % (14)%
Oil (33)% (11)% (40)%
Natural gas revenues for fiscal 1999 compared to 1998 decreased 6% as a
result of a 9% decrease in production and despite a 5% increase in average
prices. Average gas prices improved from somewhat depressed 1998 prices which
had resulted from a warm winter and a high level of inventory of storage gas.
Production volumes for 1999 decreased as a result of production declines not
fully offset by production from newly completed development wells and from a
lack of exploratory successes.
Oil revenues for 1999 were down 5% from 1998 as a result of a 26% increase
in the average price received because sales volumes were 24% lower. Oil revenues
and average prices for 1999 were also reduced by $34,000 ($.20 per barrel) due
to hedging activity while no oil hedges existed in 1998. Oil production has
declined steadily commensurate with a lack of development drilling activity
because of depressed oil prices. However, one exploratory oil well in Harris
County, Texas, drilled during 1998, was finally hooked-up to a gas line and
commenced flowing 200 barrels per day with associated gas during June 1999.
Columbus owns a 19.5% working interest.
Columbus' 1999 sales volumes of natural gas averaged 8,751 Mcf per day
while oil and liquids sales declined to 456 barrels per day. This equates to
daily production of 1,915 barrels of oil equivalent (BOE) which was down 14%
from the record 2,223 BOE during 1998.
A ratio of oil versus natural gas production during 1999 reveals that the
Company now realizes approximately 76% of its production from natural gas. Such
a high percentage is in keeping with expected results commensurate with the
change in emphasis by management during the last several years toward exploring
for and developing natural gas reserves.
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Natural gas revenues for 1998 decreased 14% compared to 1997 primarily as
a result of lower prices which more than offset improved gas production from new
wells in the Texas Gulf Coast area. These new discoveries had mitigated a normal
annual production decline plus the sale of a Berry R. Cox field property in
Texas during fourth quarter 1997. Average prices for natural gas in 1998
decreased 18% compared to 1997 as a result of reduced demand from both a warm
winter and the highest percentage of storage refill ever accomplished. Gas
revenues for 1997 were reduced by $86,400 ($.03 per Mcf) from swaps of natural
gas.
Oil revenues for 1998 versus 1997 were down by a significant 40% as a
result of a substantial 33% decrease in the average price along with a lower
sales volume of 11% which reflected a very sharp decline related to a 90%-owned
Montana oil well. This well had been recompleted in a new zone uphole during
1997's third quarter and contributed most of its initial flush production for
the last few months of that year. Furthermore, during 1998's third quarter,
several oil wells which had been marginal because of low prices were shut down
and any well which had pump or tubing problems was not repaired nor any
workovers performed. Unfortunately no crude oil swap existed during 1998 to
offer protection from that price debacle because one was in place during a
portion of 1997 when prices were high which reduced revenues. Oil revenues for
1997 were decreased by $13,600 ($.06 per barrel) from crude oil swaps.
U.S. oil prices have fluctuated for several years similar to the same wide
swings experienced in world crude oil prices. From the beginning of 1997, world
and U.S. crude oil prices steadily softened from almost $23.00 per barrel with
the decline continuing unabated throughout fiscal 1998 and reached a year end
price of $11.50 per barrel. Crude oil prices finally began to show recovery late
in 1999's second quarter and have since accelerated during the third and fourth
quarters reaching approximately $26.00 per barrel by year-end.
Lease operating expenses for 1999 were 11% lower than 1998's. Expensive
workovers and replacements of downhole and surface equipment on older wells
occurred earlier in 1998 while several of those older wells remained shut-in
during 1999's first half. 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 costs on a barrel of oil
equivalent basis for 1999 approximated $2.72 compared to $2.63 in 1998 and $2.27
for 1997. Operating costs as a percentage of revenues were 19% in 1999 compared
to 20% in 1998 which had both lower unit prices and higher costs. During 1997
costs were only 13% due to increased production and commodity prices when
compared with 1998 or 1999.
Production and property taxes approximated 10% of revenues in 1999 and
1998 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
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relationship of taxes and revenue is not always directly proportional since
several of the local jurisdiction's property taxes are based upon reserve
evaluations as opposed to revenues received or production rates for a given tax
period.
Operating and Management Services
This segment of the Company's 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 profit was $502,000 for 1999 up
substantially from the $276,000 for 1998 and the $349,000 for 1997. The 1999
profit benefited from an increase in operated wells plus an ownership increase
from 50% to 100% in four compressors operating in South Texas although profits
therefrom were adversely affected by significant compressor repairs. During 1999
the Company's contract operator services in the B. R. Cox field contributed
$100,000 to operating and management services income and profit but this is
expected to be terminated in fiscal 2000. The 1998 profit was lower as a result
of unusually high 1998 workover expenses required to clean out sand from the
well bore of a salt water disposal well in Texas although 1998's second half
revenue did show improvement with the increase in well activity along with the
aforementioned increased ownership interest in the four compressors.
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 declined in 1999 to $100,000 compared to 1998's $141,000 as a
result of reduced short-term interest rates and a lower amount of investments.
Likewise 1998 was lower than the $147,000 for 1997 for the same reasons.
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 1999 were 9% less
than last year and would have been even greater except for total phase out
during the second quarter of 1999 of reimbursement for management services
provided Resources. This had the effect of increasing costs by the amount
credits of $33,000 for 1999 were lower than $218,000 for 1998. Salary expenses
were comparable in 1999 and 1998 because increases were granted effective
December 1, 1998 for non-officer employees while officer salaries remained
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<PAGE>
unchanged and incentive compensation and bonuses were reduced in 1999. Such
bonuses are discretionary and directly related to the Company's performance
during a prior year. These amounted to only $80,000 ($58,000 non-cash) for 1999.
Higher medical claims in 1999 under the Company's self-insured plan raised
expenses. A one-time charge for a retirement pay accrual of $111,000 was
approved by the Board of Directors during 1999 for one officer and has been
reported as a separate line item.
One of the Company's working interest owners is now disputing its 25%
participation in the Long #4 well in Texas after paying $90,000 of approximately
$300,000 of its share of drilling costs. This dispute came after the well was
determined to be a dry hole. In the Company's opinion, the claim is groundless
but in the short- term will affect the collectability of its joint interest
receivable.
The Company's general and administrative expenses for 1998 were 7% higher
than fiscal 1997 due primarily to higher medical claims and increased incentive
bonuses which totaled $273,000 ($153,000 non-cash) as of May, 1998 compared to
$220,000 ($70,000 non-cash) in May, 1997. Also, some 1998 cost increases
resulted from salary adjustments granted effective December 1, 1997 for
non-officer employees as well as the May 1, 1998 raises 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 from 1997
which had included costs related to a registration statement filing which was
canceled.
Reimbursement for services provided by Columbus officers and employees for
managing Resources and providing services has had the net effect of reducing
overall general and administrative expenses. These amounted to $33,000 in 1999,
$218,000 for 1998 and $255,000 for 1997.
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.
Total charges for depletion expense for oil and gas properties was lower
in 1999 compared to 1998 as a result of decreased units of production,
especially in higher rate pools, and despite additional development
expenditures. This expense item for 1998 was higher than in 1997 as a result of
increased production plus added development expenditures during the intervening
period and a reduction in reserves in several cost pools.
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During 1999 the depletion rate was $4.69 per barrel of oil equivalent
("BOE") or $.79 per thousand cubic feet of gas equivalent ("Mcfe") compared to
1998's rate of $4.64 per BOE ($.77 per Mcfe). The depletion and depreciation
rate for fiscal 1998 increased over 1997 because of 1998's reduced crude oil
reserves in certain cost pools and an exceptionally low $3.91 per BOE ($.65 per
Mcfe) recorded for fiscal 1997.
Effective October 1, 1997 the Company sold 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 and
so those sale proceeds reduced the carrying costs of the successful efforts pool
and no book gain or loss was recognized.
Exploration Expense
In general, the exploration expense category includes the cost of
Company-wide efforts to acquire and explore new prospective areas. The
successful efforts method of accounting for oil and gas properties requires
expensing the costs of unsuccessful exploratory wells including associated
leaseholds. Other exploratory charges such as seismic and 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 which capitalize such costs.
Exploration charges of $3,071,000 for 1999 were a record and far in excess
of 1998's $722,000. Costs for 1999 included $1,443,000 to initially drill and
eventually deepen the Long #3 exploratory well in the El Squared prospect. The
Long #3 wellbore had drilling ceased and was abandoned in January 2000 for yet a
second time when the Long #4 well failed to find commercial natural gas reserves
in the upper Massive zone of the middle Wilcox. Long #4 well dry hole costs
totaled $911,000 as of year end which included associated leaseholds which were
also expensed. Seismic interpretation costs of $72,000 in the El Squared
prospect in Texas were expensed. During fiscal 1999 an additional $453,000 was
expensed for participation in five other exploratory dry holes. Subsequent to
fiscal year end about $1,200,000 was further incurred while drilling and
eventually abandoning the Long #3 and #4 wells. This amount will be recognized
as an exploration expense during first quarter of fiscal year 2000.
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Whenever a company using the successful efforts method of accounting is
involved in an exploratory program that represents a significant part of its
budget, it is automatically subjected to the risk that net earnings for any
given quarter or year will be impacted negatively by wildcat dry holes. The
numerous exploratory well bores involved at Columbus' El Squared Prospect that
have already been or will be required to be drilled to properly evaluate the
various fault blocks and/or potential producing horizons certainly fit that
circumstance. Shareholders have been forewarned that net earnings and GAAP cash
flow may not be truly indicative of the Company's operational activity. This is
why management suggests that shareholders may wish to follow its own assessment
of placing more emphasis on DCF from year to year and ignore net earnings.
Comparing EGY's results with other company's net earnings or cash flows when
they use the full cost accounting method is unrealistic and ill advised because
they capitalize such exploratory costs.
Exploration expense for 1998 of $722,000 included two exploratory dry
holes in the S.E. Froid area in Montana where $209,000 was expensed while in the
Texas Gulf Coast area a second dry hole cost $142,000. No exploratory oil wells
could be justified during 1998 on any of its 3-D seismic structures mapped on
its Williston Basin leasehold blocks in Montana until crude oil prices showed
significant improvement. Early in 1998 3-D seismic costs of $135,000 had been
incurred in this area in anticipation there would be an improvement in crude oil
prices during the year and before leasehold expirations occurred during 1999.
Exploration charges for 1997 were $540,000. These included $224,000 of 3-D
seismic costs incurred in the S.E. Froid area in Montana in an attempt to locate
new exploratory well sites plus $73,000 incurred for drilling a non-commercial
exploratory oil well.
Litigation Expense
The litigation expense in 1999 and 1998 relates to the Maris E. Penn, et
al lawsuit previously described.
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 1999 than in 1998. The average bank interest rate paid for debt in
1999, 1998 and 1997 was 6.6%, 7.1%, and 7.1%, respectively.
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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 current Federal and state taxes payable of 2% to 3% of
pre-tax earnings. For use in fiscal 1999, the Company has a net operating loss
carryforward from 1995 and operating loss carryforwards remaining from periods
prior to the Section 382 ownership changes. Utilization of those latter benefits
are limited to $1,707,000 for fiscal 1999, which expire if not used, and
$904,000 in fiscal 2000. The significant exploration costs incurred during 1999
and first quarter of fiscal 2000 will reduce taxable income and may result in
net operating losses expiring before they are utilized. The Company's current
Federal tax provision and liability might increase after fiscal 2000 unless an
active drilling program is maintained. In addition, the Company pays state
income taxes in some states.
During 1999, the net deferred tax asset increased to $1,137,000 which was
comprised of $200,000 current portion and $937,000 long- term asset. The
valuation allowance had a net reduction of $122,000 from 1998 to November 30,
1999. A deduction of $12,000 for the benefit of disqualifying disposition of
incentive stock options was added to additional paid-in capital.
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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New Accounting Pronouncements
In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date for SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," to fiscal years beginning after June 15, 2000. The Company must
apply this statement no later than its fiscal year beginning December 1, 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 three years. Competition in the industry can
significantly affect the cost of acquiring leases, although in the past decade
competition has lessened as more operators have withdrawn from active
exploration programs. Inflation, as well as a recessionary period, can cause
significant swings in the interest rates the Company pays on bank borrowings.
These factors are anticipated to continue to affect the Company's operations,
both positively and negatively, for the foreseeable future.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's exposure to interest rate risk and commodity price risk is
discussed in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Liquidity and Capital Resources".
The Company has no exposure to foreign currency exchange rate risks or to any
other market risks.
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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 46.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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PART III
Items 10 and 11. DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT AND EXECUTIVE COMPENSATION
A definitive proxy statement related to the 2000 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 2000 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 2000 Annual Meeting of Stockholders
and is incorporated herein by reference.
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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 46.
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 1999:
None
(c) Exhibits:
Exhibit No.
- -----------
* 3.1 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).
* 3.2 Amended By-Laws of Columbus Energy Corp. amended as of May
5, 1999 (Exhibit 3(b) to Form 8-K dated May 5, 1999).
*10.1 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).
*10.2 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).
*10.3 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).
*10.4 Third Amendment of Credit Agreement dated May 12, 1999
between Columbus Energy Corp. and Norwest Bank Colorado,
National Association (Exhibit 10.1 to Form 10-Q dated May
31, 1999).
44
<PAGE>
*10.5 1993 Stock Purchase Plan (Exhibit to Registration Statement
No. 33-63336).
*10.6 1995 Stock Option Plan (Exhibit 10(k) to Form 8-K dated May
11, 1995).
*10.7 1985 Stock Option Plan (Exhibit to Registration Statement
No. 33-17885).
*10.8 1985 Stock Option Plan, Amendment No. 2 dated November 7,
1991 (Exhibit 10(h) to Form 10-K dated November 30, 1991).
*10.9 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).
*10.10 Form of Indemnity Agreements with directors (Exhibit 10(k)
to Registration Statement No. 33-46394).
22 Subsidiaries of the Registrant.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2 Consent of Reed W. Ferrill & Associates, Inc.
27 Financial Data Schedule
- ---------------
*Incorporated by reference
45
<PAGE>
COLUMBUS ENERGY CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Report of Independent Accountants 47
Financial Statements:
Consolidated Balance Sheets at
November 30, 1999 and 1998 48
Consolidated Statements of Operations for the
years ended November 30, 1999, 1998 and 1997 50
Consolidated Statements of Stockholders'
Equity for the years ended
November 30, 1999, 1998 and 1997 51
Consolidated Statements of Cash Flows for the
years ended November 30, 1999, 1998 and 1997 53
Notes to the Consolidated Financial Statements 54
46
<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, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended November 30, 1999, in conformity with accounting principles
generally accepted in the United States. 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 auditing
standards generally accepted in the United States, 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 17, 2000
47
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
------
November 30,
-------------------------
1999 1998
---- ----
(in thousands)
Current assets:
Cash and cash equivalents $ 1,850 $ 2,003
Accounts receivable:
Joint interest partners 1,780 1,570
Oil and gas sales 1,501 1,239
Allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 5) 200 327
Inventory of oil field equipment,
at lower of average cost or market 106 95
Other 80 106
------- -------
Total current assets 5,401 5,224
------- -------
Deferred income taxes (Note 5) 937 -
Property and equipment:
Oil and gas assets, successful
efforts method (Notes 3 and 4) 36,862 36,039
Other property and equipment 1,836 1,804
------- -------
38,698 37,843
Less: Accumulated depreciation,
depletion, amortization and
valuation allowance
(Notes 2 and 3) (22,506) (19,118)
-------- -------
Net property and equipment 16,192 18,725
-------- -------
$ 22,530 $23,949
======== =======
(continued)
48
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
November 30,
----------------
1999 1998
---- ----
(in thousands)
Current liabilities:
Accounts payable $ 2,352 $ 1,846
Undistributed oil and gas
production receipts 386 317
Accrued production and property taxes 738 677
Prepayments from joint interest owners 200 374
Accrued expenses 494 415
Income taxes payable (Note 5) 30 2
Other 32 37
------- ------
Total current liabilities 4,232 3,668
------- ------
Long-term bank debt (Note 4) 5,500 4,900
Deferred income taxes (Note 5) - 117
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; 4,645,303 shares
issued in 1999 and 4,611,001 in 1998
(outstanding 3,800,558 in 1999 and
4,046,552 in 1998) (Notes 1 and 7) 929 922
Additional paid-in capital 20,069 19,656
Accumulated deficit (2,655) (1,440)
------- -------
18,343 19,138
Less:
Treasury stock, at cost (Note 7)
844,745 shares in 1999 and
564,449 shares in 1998 (5,545) (3,874)
------- -------
Total stockholders' equity 12,798 15,264
------- -------
$22,530 $23,949
======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
49
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended November 30,
--------------------------------
1999 1998 1997
---- ---- ----
(in thousands, except per share data)
Revenues:
Oil and gas sales $10,014 $10,617 $13,815
Operating and management
services 1,386 1,336 1,176
Interest income and other 100 141 165
------- ------- -------
Total revenues 11,500 12,094 15,156
------- ------- -------
Costs and expenses:
Lease operating expenses 1,903 2,140 1,849
Property and production taxes 1,029 1,080 1,258
Operating and management
services 884 1,060 827
General and administrative 1,336 1,466 1,372
Depreciation, depletion and
amortization 3,400 3,846 3,295
Impairments 973 3,482 2,179
Exploration expense 3,071 722 540
Retirement and separation 111 - -
Litigation expense 119 4 10
Loss on sale of assets - - 60
------- ------- -------
Total costs and expenses 12,826 13,800 11,390
------- ------- -------
Operating income (loss) (1,326) (1,706) 3,766
------- ------- -------
Other (income) expense:
Interest 373 260 174
Other 62 26 (4)
------- ------- ------
435 286 170
------- ------- ------
Earnings (loss) before
income taxes (1,761) (1,992) 3,596
Provision (benefit) for income
taxes (Note 5) (546) (757) 1,429
------- ------- ------
Net earnings (loss) $(1,215) $(1,235) $ 2,167
======= ======= =======
Earnings (loss) per share (Note 8):
Basic $ (.31) $ (.29) $ .50
======= ======= =======
Diluted $ (.31) $ (.29) $ .49
======= ======= =======
Weighted average number of common and
common equivalent shares outstanding:
Basic 3,898 4,194 4,299
======= ======= =======
Diluted 3,898 4,194 4,392
======= ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
50
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Three Years Ended November 30, 1999
<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, 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
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 - - -
(continued)
</TABLE>
51
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - (continued)
For the Three Years Ended November 30, 1999
<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>
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)
--------- ------- ------- ------- ------- -------
Exercise of employee
stock options 23,320 5 63 - 855 24
Purchase of shares - - - - 300,540 (1,836)
Shares issued for Stock
Purchase Plan 10,982 2 66 - (2,759) 19
Shares issued for
Incentive Bonus Plan
and directors' fees - - (38) - (18,340) 122
Tax benefit of stock option
exercises - - 12 - - -
Income tax benefit of
loss carryforwards
arising prior to
quasi-reorganization - - 310 - - -
Net loss - - - (1,215) - -
--------- ------ ------- ------- ------- -------
Balances,
November 30, 1999 4,645,303 $ 929 $20,069 $(2,655) 844,745 $(5,545)
========= ====== ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
52
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended November 30,
----------------------------------
1999 1998 1997
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Net earnings (loss) $(1,215) $(1,235) $ 2,167
Adjustments to reconcile net earnings (loss) to
net cash provided by operating activities:
Depreciation, depletion, and
amortization 3,400 3,846 3,295
Impairments and loss on asset dispositions 973 3,482 2,179
Deferred income tax provision (benefit) (606) (822) 1,328
Exploration expense, non-cash portion 328 9 -
Other 147 190 163
Changes in operating assets and liabilities:
Accounts receivable (472) 1,177 (1,554)
Other current assets (28) (7) 21
Accounts payable 673 (298) 352
Undistributed oil and gas production receipts 69 (76) 339
Accrued production and property taxes 61 126 (4)
Prepayments from joint interest owners (174) (191) 307
Income taxes payable 28 18 9
Other current liabilities 74 39 36
------- ------- -------
Net cash provided by operating activities 3,258 6,258 8,638
------- ------- -------
Cash flows from investing activities:
Proceeds from sale of assets - 36 1,005
Additions to oil and gas properties (2,291) (6,642) (8,172)
Additions to other assets (45) (111) (127)
------- ------- -------
Net cash used in investing activities (2,336) (6,717) (7,294)
------- ------- -------
Cash flows from financing activities:
Proceeds from long-term debt 1,300 3,400 3,000
Reduction in long-term debt (700) (700) (3,000)
Proceeds from exercise of stock options 161 455 498
Purchase of treasury stock (1,836) (2,550) (1,381)
------- ------- -------
Net cash provided by (used in)
financing activities (1,075) 605 (883)
------- ------- -------
Net increase (decrease) in cash and cash equivalents (153) 146 461
Cash and cash equivalents at beginning of year 2,003 1,857 1,396
------- ------- -------
Cash and cash equivalents at end of year $ 1,850 $ 2,003 $ 1,857
======= ======= =======
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 373 $ 254 $ 182
======= ======= =======
Income taxes, net of refunds $ 32 $ 47 $ 91
======= ======= =======
Supplemental disclosure of non-cash investing
and financing activities:
Non-cash compensation expense
related to common stock $ 116 $ 190 $ 98
======= ======= =======
Use of loss carryforwards credited to
additional paid-in-capital $ 310 $ 220 $ 262
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
53
<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
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
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 statements 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.
54
<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, 1999 and 1998 the Company had investments
in commercial paper of $1,300,000 and $1,100,000, 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, counterparties 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.
55
<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,
1999 and 1998.
Other Property and Equipment
Other property and equipment consists of compressors, vehicles, office
and computer equipment and software. 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, which range from three to twelve
years.
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.
56
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Earnings Per Share
Basic earnings per share is computed based on the weighted average
number of shares outstanding. Diluted earnings per share reflects the potential
dilution that would occur if options were exercised using the average market
price for the Company's stock for the period. 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
In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date for SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," to fiscal years beginning after June 15, 2000. The Company must
apply this statement no later than its fiscal year beginning December 1, 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.
57
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(3) OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth the capitalized costs related to U.S.
oil and gas producing activities, costs incurred in oil and gas property
acquisition, exploration and development activities, and results of operations
for producing activities:
Capitalized Costs Relating to Oil and Gas
Producing Activities
(in thousands)
November 30,
----------------------------
1999 1998
------- -------
Proved properties $36,456 $35,290
Unproved properties 406 749
------- -------
36,862 36,039
Less accumulated depreciation,
depletion, amortization and
valuation allowance (21,221) (17,919)
------- -------
Total net properties $15,641 $18,120
======= =======
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities
(in thousands)
Year Ended November 30,
-------------------------------
1999 1998 1997
------ ------ -----
Property acquisition
costs:
Proved $ - $ 74 $ -
Unproved 226 764 508
Exploration costs 3,071 722 540
Development costs 1,927 4,925 9,043
------ ------ ------
Total costs incurred $5,224 $6,485 $10,091
====== ====== =======
58
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Results of Operations for Producing Activities
(in thousands)
Year Ended November 30,
-----------------------------
1999 1998 1997
------ ------ -----
Sales $10,014 $10,617 $13,815
Production (lifting)
costs (a) 2,932 3,220 3,107
Exploration expenses 3,071 722 540
Impairment of long-
lived assets 973 3,482 2,179
Depreciation
depletion and
amortization (b) 3,301 3,743 3,194
------- ------- ------
(263) (550) 4,795
Income tax provision
(benefit) (82) (209) 1,905
------- ------- ------
Results of operations
from producing
activities
(excluding overhead
and interest
incurred) $ (181) $ (341) $2,890
======= ======= ======
(a) Production costs include lease operating expenses, production
and property taxes
(b) Amortization expense per equivalent barrel of production:
1999 - $4.69 1998 - $4.64 1997 - $3.91
For the years ended November 30, 1999, 1998 and 1997, 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.
1999 1998 1997
------------------ ------------------ -------------------
Amount % Revenue Amount % Revenue Amount % Revenue
------ --------- ------ --------- ------- ---------
Customer A $1,521 15.2% $1,652 15.6% $ 2,956 21.4%
Customer B 4,528 45.2 5,204 49.0 6,536 47.3
Customer C - - - - 1,395 10.1
Customer D 1,465 14.6 1,321 12.4 - -
In the Company's judgment, termination by any purchaser to 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.
59
<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 May 12, 1999 the
Credit Agreement was amended to extend the revolving period to July 1, 2001 when
it entirely converts to an amortizing term loan which matures July 1, 2005. The
credit is collateralized by a first lien on oil and gas properties. The interest
rate options are the Bank's prime rate or LIBOR plus 1.50%. In addition, a
commitment fee of 1/4 of 1% of the average unused portion of the credit is
payable quarterly.
At November 30, 1999 outstanding borrowings on the revolving line of
credit were $5,500,000 and the unused borrowing base available was $4,500,000.
The $5,500,000 bears interest at LIBOR rate of 5.51% 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 for the years ending November
30 are as follows (in thousands):
2001 $ 458
2002 1,375
2003 1,375
2004 1,375
2005 917
-------
Total $ 5,500
=======
60
<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):
1999 1998 1997
---- ---- ----
Current:
Federal $ 28 $ - $ 13
State 32 65 88
------ ------ ------
60 65 101
------ ------ ------
Deferred:
Federal (582) (789) 942
Use of loss carryforwards - - 347
State (24) (33) 39
------ ------ ------
(606) (822) 1,328
------ ------ ------
Total income tax
provision (benefit) $ (546) $ (757) $1,429
======= ====== ======
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
----------------------------------------
1999 1998 1997
---- ---- ----
U.S. statutory rate (34)% (34)% 34 %
State income taxes 1 2 2
Change in valuation
allowance - (4) 2
Other 2 (2) 2
--- --- ---
Effective rate (31)% (38)% 40 %
=== === ===
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.
61
<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 1999, certain tax assets (shown in the table below) were
utilized and the valuation allowance was decreased during the year by $122,000.
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,
1998 Equity Other 1999
-------- ------------ ----------- ------
<S> <C> <C> <C> <C>
Deferred tax assets:
Pre-1987 loss carryforwards $1,049 $ - $ (609) $ 440
Post-1987 loss carryforwards 615 - 2 617
Percentage depletion
carryforwards 1,478 - 172 1,650
State income tax loss
carryforwards 118 - 6 124
Other 329 - 58 387
------ ----- ----- ------
Total 3,589 - (371) 3,218
Valuation allowance (long-term) (1,408) 310(a) (188) (1,286)
------ ----- ----- ------
Deferred tax assets 2,181 310 (559) 1,932
------ ----- ----- ------
Tax benefit of stock option
exercises - 12(a) (12) -
------ ----- ------ ------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (1,971) - 1,176 (795)
------ ----- ------ ------
Net tax asset $ 210 $ 322 $ 605 $1,137
====== ===== ======= ======
</TABLE>
(a) Credited to additional paid-in capital.
62
<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, 1999 as follows:
Net
Expiration Year Operating Loss
--------------- --------------
2000 $ 904
2001 387
2003 105
2004 115
2010 1,593
-------
$ 3,104
=======
For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of approximately $3,219,000 as of November 30, 1999. The Company
also has percentage depletion carryforwards of $4,344,000 which do not expire.
Oklahoma state income tax operating loss carryforwards total approximately
$2,075,000 at November 30, 1999. These carryforwards begin to expire in fiscal
2003 and have a full valuation allowance and no net asset value in these
financial statements.
The earnings before income taxes for financial statements differed from
taxable income as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Earnings (loss) before income taxes
per financial statements $(1,761) $(1,992) $ 3,596
Differences between income before taxes
or financial statement purposes and
taxable income:
Intangible drilling costs
deductible for taxes (453) (2,685) (6,158)
Excess of book over tax
depletion, depreciation
and amortization 2,212 1,800 1,683
Tax benefit of stock option
exercises (32) (229) (200)
Impairment expense 973 3,426 1,843
Lease abandonments (393) (74) (13)
Geological expense 318 - -
Other 153 (10) 153
------ ------ -------
Federal taxable income $ 1,017 $ 236 $ 904
======= ======= =======
</TABLE>
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, 1999 as well as contemplated drilling
63
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 $1,286,000 as of November 30, 1999, $206,000
relates to pre-quasi- reorganization tax assets and the balance of $1,080,000
relates to post-quasi-reorganization tax assets. In future periods, any
reduction of the pre-quasi-reorganization portion of the valuation allowance
will be credited to additional paid-in capital and any 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 $8,500,000 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 $3,218,000. This level of income can be achieved using the value of proved
reserves reported in the year end November 30, 1999 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 1999 the valuation allowance
was decreased by $310,000 related to pre-quasi- reorganization tax assets and
increased by $188,000 for post-quasi- reorganization tax assets. 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.
(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 $33,000 for fiscal 1999,
$218,000 for fiscal 1998 and $225,000 for fiscal 1997.
During fiscal 1997, the Company continued its consulting and drilling
arrangements with Trueblood Resources , Inc ("TRI") that began in 1995 and
continued each year with amendments as appropriate for each year's program. In
1997 there was a 90-day written notice provision in addition to the monthly
64
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
retainer fee of $10,000 for geological and geophysical consulting services
provided by Mark Butler, a Vice President of TRI, who would dedicate a total of
135 hours each three-month period reviewing prospects of third parties and
supervising and planning 3D seismic programs on Columbus' leaseholds. Also,
there was to be continued participation for a 37.5% working interest in the AMI
located in the Anadarko Basin primarily located in two counties in the Oklahoma
Panhandle. TRI is a privately held oil and gas exploration and production
company whose major shareholder is John Trueblood, the son of Columbus' CEO,
Harry A. Trueblood, Jr., who is a director and also was a 1.2% shareholder of
TRI. Also, there is a related company to TRI known as Trumark Production
Company, LLC ("TPC") in which Mark Butler and John Trueblood each own 50% which
is primarily a technical services oriented company for which TRI serves in an
administrative capacity therefor.
In November 1997, an amended agreement was created to cover 1998 fiscal
year operations and superseded and replaced the original 1995 agreement and
supplements thereto. Columbus and TRI formed a new AMI which included all of
Texas County, Oklahoma wherein Columbus would take up to a one-third working
interest participation and the remainder belonged to TRI. The Company advanced
$30,000 to acquire digitized logs and related software for use in the search for
new prospects in Texas County with the resulting data to be owned by Columbus.
To compensate for the advance, TRI agreed to waive any cash promotion on the
first four prospects generated from the data and further reduced the 10% carried
working interest promotion on the 100% WI to 5% in the first two of those
prospects. The retainer fee of $10,000 per month was continued covering up to
135 hours in each three months period of Mr. Butler's time to perform certain
geological and geophysical services. Also TRI would have the right to
participate for up to a proportionate 5.0% WI in any third party deal reviewed
by Mr. Butler and taken by the Company.
For fiscal 1999, two separate agreements dated December 1, 1998 were
entered into by the Company. One was with TPC wherein Mr. Butler increased his
base consulting to 70 hours per month and his other time would be devoted to
finding prospects in the Oklahoma AMI for TRI's operations with third party
participants as well as with Columbus. The retainer would be at the rate of $170
per hour which would result in a monthly retainer charge of $11,900. For each
prospect review by Mr. Butler and taken by Columbus, TPC would receive a 2%
proportionately reduced carried working interest through logs but certain
existing areas of operations were specifically excepted from this arrangement.
65
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The second agreement was with TRI and basically gave Columbus the option to
participate in the Oklahoma prospects during the year with no carried working
interest burden related to its proportionate share of such prospects that might
be drilled.
As a result of the above contracts, retainer fees paid to TRI for TPC's
consulting services, etc. were $155,000 in fiscal 1999, $179,000 in 1998, and
$121,000 in 1997. Promotional costs plus associated actual costs of drilling
wells involved which were paid to TRI amounted to $348,000 in 1999, $5,000 in
1998 and $614,000 in 1997. The amounts are paid monthly and at each year-end no
other amounts were owed.
(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 the 10% stock dividend in
fiscal 1998.
Columbus has several stock option plans with outstanding options for the
benefit of all employees. Under the 1985 Plan, options for 42,178 shares were
exercisable at November 30, 1999. No additional options may be granted under the
1985 Plan. At November 30, 1998, 63,731 shares were exercisable.
Under the 1995 Plan, as of November 30, 1999, 17,487 option shares remained
available for granting, and options for 287,752 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, 1998, 6,937
shares were available for granting, and options for 314,182 shares were
exercisable.
The Board of Directors has granted non-qualified stock options of which
there were 329,886 exercisable at November 30, 1999 and 231,803 shares were
exercisable at November 30, 1998. The Board of Directors has reserved 475,000
shares of treasury stock to be used for issuing common stock when non-qualified
stock options are exercised.
66
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 fixed stock options granted with an exercise price equal to or
greater than 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:
1999 1998 1997
---- ---- ----
(thousands except per share amounts)
Net income (loss)
As reported $(1,215) $(1,235) $2,167
Pro forma (1,340) $(1,392) $1,968
Earnings (loss) per
share (basic)
As reported $ (.31) $ (.29) $ .50
Pro forma $ (.34) $ (.33) $ .46
67
<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, 1999:
1999 1998 1997
---------------- ---------------- ----------------
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 619 $6.73 557 $6.45 490 $5.65
Granted 246 $5.93 182 $6.76 191 $7.38
Exercised (67) $5.40 (115) $5.34 (121) $4.70
Expired (49) $6.46 (5) $7.79 (3) $6.64
---- ---- ----
Shares under option at
end of year 749 $6.61 619 $6.73 557 $6.45
==== ==== ====
Options exercisable
at November 30 660 $6.74 610 $6.73 542 $6.42
Shares available for
future grant at end
of year 17 7 46
Weighted-average fair value
of options granted during
the year $1.07 $1.40 $2.04
The following table summarizes information about the Company's stock
options outstanding at November 30, 1999:
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 - $5.79 137 2.1 $ 5.57 52 $ 5.58
$6.12 - $6.44 273 2.4 $ 6.21 269 $ 6.21
$7.00 - $7.84 339 1.5 $ 7.34 339 $ 7.34
--- --- ------ --- ------
$4.68 - $7.84 749 2.0 $ 6.61 660 $ 6.74
=== === ====== === ======
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:
1999 1998 1997
---- ---- ----
Expected option life - years 2.30 2.32 2.36
Risk-free interest rate 5.50% 5.02% 6.08%
Dividend yield 0 % 0 % 0 %
Volatility 19.94% 25.87% 30.60%
68
<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. The Company
contributes an amount of shares equivalent to 25% of those payments which are
issued out of the Company's treasury stock as vesting occurs semi- annually. The
price of the issued shares equals the average trading price during each six
month purchase period or the ending price, whichever is less. The following
table summarizes the Stock Purchase Plan activity for the last three fiscal
years:
Matching Total Shares from Average
Contributions Shares Treasury Cost
Fiscal Year Expense Purchased Stock Per Share
- ----------- ------- --------- ----- ---------
1997 $15,000 8,758 1,762 $8.58
1998 $17,000 11,298 2,275 $7.73
1999 $16,000 13,741 2,759 $6.30
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*
----------- ------------ --------- -------
1997 158,000 197,863 $6.92
1998 352,750 357,715 $7.07
1999 300,538 300,538 $6.08
*Restated for stock split and stock dividends
As of November 30, 1999 a total of 73,384 shares remained to be purchased
from the most recent authorizations to repurchase shares at a price not to
exceed $6.00 per share. As of January 31, 2000, 45,000 of those shares have
subsequently been acquired at an average price of $5.61 per share.
69
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(8) EARNINGS PER SHARE
The following table provides a reconciliation of basic and diluted
earnings per share (EPS):
Fiscal Year Ended November 30,
------------------------------
1999 1998 1997
---- ---- ----
(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) $(1,215) $(1,235) $2,167
======= ======= ======
Shares (denominator):
Basic EPS 3,898 4,194 4,299
Effect of dilutive option
shares - - 93
------- ------ ------
Diluted EPS 3,898 4,194 4,392
======= ====== ======
Per share amount:
Basic EPS $ (.31) $ (.29) $ .50
======= ====== ======
Diluted EPS $ (.31) $ (.29) $ .49
======= ====== ======
Number of shares not included in
dilutive EPS that would have been
antidilutive because exercise price
of options was greater than the
average market price of the common
shares 544 138 73
======= ====== ======
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.
70
<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 its present office space. The
total rent expense for 1999, 1998 and 1997 was approximately $200,000, $171,000
and $161,000, respectively. Columbus has extended the lease for an additional
one year through September 2000 at a base rate of $21,525 per month. Future
rental payments required under this lease as of November 30, 1999 are $215,000
for fiscal year 2000.
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, 1999
the accrued liability totals $290,000 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 $120,000,
$18,000 and $23,000 in 1999, 1998 and 1997, respectively.
71
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Columbus periodically hedges both natural gas and crude oil prices by
entering into "swaps". The swap is 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. There was no hedging activity in
fiscal 1998. The following table shows the results of these swaps:
<TABLE>
<CAPTION>
Increase (decrease) in
oil and gas revenues
Volume -----------------------
Description per mo. Period 1999 1997
- ----------- -------------- ------ ---- ----
(Mmbtu or bbl)
<S> <C> <C> <C> <C>
Natural Gas
- -----------
$2.20/Mmbtu 60,000 3/97-10/97 $(86,400)
Crude Oil
- ---------
Collar with $17.50/
bbl floor and
$22.25/bbl ceiling 7,500 9/99- 8/00 $(34,000)
$21.17/bbl 10,000 11/96-10/97 $ 8,900
$17.25/bbl with
$19.50/bbl cap 10,000 1/96-12/96 $(22,500)
</TABLE>
The Company's natural gas and crude oil swaps are considered financial
instruments with off-balance sheet risk which are entered into in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those instruments involved, to varying degrees,
elements of market and credit risk in excess of the amount recognized in the
balance sheets.
The Company had a crude oil hedge outstanding as of November 30, 1999 by
using a costless "collar" on 7,500 barrels per month for the 12 months from
September 1, 1999 through August 31, 2000. This "collar" is settled monthly
against the calendar monthly average price on the NYMEX with a $17.50 per barrel
floor and $22.25 per barrel ceiling. For any average price below or above those
prices Columbus receives or pays the difference which increases or reduces oil
revenues each month in which this occurs. For the two months of December, 1999
and January, 2000, oil sales would have been $65,000 higher if this hedge had
not been in place because oil prices exceeded the $22.25 ceiling price. For the
remaining period of February through August 2000 using the prevailing price as
of January 31, 2000 for each of the months, the settlement value the Company
would owe is $158,000 which would also reduce crude oil sales.
72
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company is not aware of any events of noncompliance in its operations
with any environmental laws and regulations nor of any potentially material
contingencies related to environmental issues. There is no way management can
predict what future environmental control problems may arise. The continually
changing character of environmental regulations and requirements that might be
enacted by jurisdictional authorities in various operational areas defies
forecasting.
On October 7, 1998, Columbus was served with a complaint in a lawsuit
styled Maris E. Penn, Michael Mattalino, Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98- 44940 in the 55th District Court of
Harris County, Texas. The plaintiffs are parties to a September 1994 settlement
agreement that provided for the conveyance of overriding royalty interests in
leases acquired by Columbus in certain portions of Harris County. Plaintiffs
claim Columbus is obligated under the settlement agreement to acquire all leases
available within a described portion of Harris County and that Columbus has
failed to develop those leases as a reasonably prudent operator. Plaintiffs are
claiming damages based upon their alleged right to a 3% overriding royalty
interest in leases taken and drilled by third parties within the described area.
Discovery is ongoing. Columbus denies all allegations of failure to develop and
instructed counsel to vigorously defend this lawsuit. The parties are set for
mediation on April 11, 2000 and for trial on May 22, 2000.
(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 $110,000,
$106,000, and $95,000 in the fiscal years 1999, 1998 and 1997, respectively.
73
<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:
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Operating revenues from unaffiliated services:
Oil and gas $10,022 $10,630 $13,848
Services 1,478 1,464 1,308
------- ------- -------
Total $11,500 $12,094 $15,156
======= ======= =======
Depreciation, depletion and amortization (a):
Oil and gas $ 3,341 $ 3,784 $ 3,238
Services 59 62 57
------- ------- -------
Total $ 3,400 $ 3,846 $ 3,295
======= ======= =======
Operating income (loss):
Oil and gas $ (294)(b) $ (582)(b) $ 4,714(b)
Services 415 342 424
General corporate expenses (1,447) (1,466) (1,372)
------- ------- -------
Total operating income (loss) (1,326) (1,706) 3,766
Interest expense and other (435) (286) (170)
------- ------- --------
Earnings (loss) before income taxes $(1,761) $(1,992) $ 3,596
======= ======= =======
Identifiable assets (a):
Oil and gas $18,621 $19,587 $21,917
Services 3,909 4,362 4,218
------- ------- -------
Total $22,530 $23,949 $26,135
======= ======= =======
Additions to property and equipment:
Oil and gas $ 2,215 $ 5,872 $ 9,671
Services - 45 7
------- ------- -------
Total $ 2,215 $ 5,917 $ 9,678
======= ======= =======
</TABLE>
(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 $973,000 in 1999, $3,482,000 in 1998
and $2,179,000 in 1997.
74
<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 17, 2000 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 2/17/00
- ----------------------------- ---------
Harry A. Trueblood, Jr.
Chief Operating Officer
Executive Vice President
/s/ Clarence H. Brown and Chief Operating Officer 2/17/00
- ----------------------------- ---------
Clarence H. Brown
Principal Accounting and Financial Officer
/s/ Ronald H. Beck Vice President 2/17/00
- ----------------------------- ---------
Ronald H. Beck
Majority of Board of Directors
/s/ Harry A. Trueblood, Jr. Director 2/17/00
- ------------------------------ ---------
Harry A. Trueblood, Jr.
/s/ Clarence H. Brown Director 2/17/00
- ------------------------------ ---------
Clarence H. Brown
/s/ J. Samuel Butler Director 2/17/00
- ------------------------------ ---------
J. Samuel Butler
/s/ William H. Blount, Jr. Director 2/17/00
- ------------------------------ ---------
William H. Blount, Jr.
75
<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, 1999
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, 1999
Name Ownership
---- ---------
Columbus Gas Services, Inc. 100%
Columbus Texas, Inc. 100%
Columbus Energy, L.P. (as general partner) 1%
EXHIBIT 23.1
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 17, 2000, on our audits of the consolidated
financial statements of Columbus Energy Corp. as of November 30, 1999 and 1998,
and for the years ended November 30, 1999, 1998, and 1997, which report is
included in this Annual Report on Form 10-K.
PricewaterhouseCoopers LLP
Denver, Colorado
February 17, 2000
EXHIBIT 23.2
(REED W. FERRILL & ASSOCIATES LETTERHEAD)
February 11, 2000
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, 2000 entitled "Columbus Energy Corp., Reserve and
Revenue Forecast as of November 30, 1999, 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,
1999.
for and on behalf of
Reed W. Ferrill & Associates, Inc.
\s\Reed W. Ferrill
--------------------
Reed W. Ferrill
President
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The consolidated balance sheet as fo November 30, 1999 and the consolidated
statement of income for the year ended November 30, 1999.
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<CURRENCY> U.S. Dollars
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<FISCAL-YEAR-END> NOV-30-1999
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0
0
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<CGS> 2,932
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<INCOME-PRETAX> (1761)
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<EPS-BASIC> (.31)
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