Item 1. BUSINESS
Columbus Energy Corp. ("Columbus") was incorporated under the laws of the State of Colorado on October 7, 1982. Columbus engages in the production and sale of crude oil, condensate and natural gas, as well as the acquisition and development of leaseholds and other interests in oil and gas properties, and also acts as manager and operator of oil and gas properties for itself and others. It also engages in the business of compression, transmission and marketing of natural gas through its wholly-owned subsidiary, Columbus Gas Services, Inc. ("CGSI"), a Delaware corporation. Prior to February 1995 CEC Resources Ltd. (Resources"), an Alberta, Canada corporation, was another wholly-owned subsidiary. The term "Company" as used herein includes Columbus and its subsidiaries.
The Company currently has 33 employees. The current technical staff, including management, is comprised of four petroleum engineers and one landman. The administrative staff provides support required for accounting and data processing including disbursement of monthly oil and gas revenues, joint interest billing functions, and accounts payable.
On February 24, 1995, Columbus completed a rights offering to the Columbus shareholders to purchase one share of Resources at U.S.$3.25 cash plus two subscription rights. One right was distributed as a dividend for each share held of record on January 27, 1995. All 1,500,000 shares of Resources common stock were subscribed (and oversubscribed) yielding an aggregate of $4,875,000. The total value assigned to the rights on its books was $582,000 for the dividend portion of the purchase of Resources shares. A deduction of $126,000 for the costs of the offering was recorded. No gain or loss can be recognized for book purposes in a spin-off. No taxes were due Revenue Canada as a result of this divestiture of common stock because the tax basis exceeds the proceeds received upon disposition.
From shortly after its incorporation until January 1988, the Company was a wholly-owned or majority owned subsidiary of Consolidated Oil & Gas, Inc. ("Consolidated") at 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.
Item 2.

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, 1996, 1995 and 1994 and including its wholly-owned Canadian subsidiary, Resources, for 1994.
PROVED OIL AND GAS RESERVES
Proved Developed Producing Reserves
As of November 30, 1996, Columbus has approximately 1,139,000 barrels of proved developed producing oil and condensate in the United States most of which are attributable to primary recovery operations. Producing oil properties in North Dakota, Montana and Texas account for almost 100% of the reserves in the proved developed producing category with 207,000 barrels of the Sralla Road (Vicksburg) field, Harris County, Texas, receiving some pressure maintenance assistance from produced water being injected into the aquifer.
The U.S. gas producing properties owned by Columbus are located in Texas, North Dakota, Oklahoma and Montana and contain 11.2 billion cubic feet of proved developed producing gas reserves.
The reserves in this category can be materially affected positively or negatively by either currently prevailing or future prices because they determine the economic lives of the producing wells.
Proved Developed Non-Producing Reserves
The reserves in this category are located in the states of Texas, Montana and North Dakota. Generally, these are reserves behind the casing in existing wells and recompletion of those wells will be required prior to the commencement of production.
Columbus' (U.S.) non-producing reserves are 71,600 barrels of oil, or 4.4% of its total proved oil reserves, and 4.6 billion cubic feet of natural gas, or 25% of its total proved natural gas reserves.
Proved Undeveloped Reserves
Columbus' (U.S.) proved undeveloped reserves were approximately 432,000 barrels and 2.9 billion cubic feet of natural gas. Almost all of the oil reserves in this category are in Montana, North Dakota and Texas, and all of the proved undeveloped gas reserves are attributable to undrilled locations offsetting production in Webb, Zapata and Jim Hogg Counties, Texas, Montana and North Dakota.
These reserves are expected to be developed during 1997 or in future years assuming oil and gas prices stabilize at prices which yield a satisfactory rate of return on investment when developed.
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 Financial Accounting Standards Board Statement 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)
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES FOR THE THREE YEARS ENDED NOVEMBER 30, 1996 (thousands of dollars)
(continued)
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES FOR THE THREE YEARS ENDED NOVEMBER 30, 1996 - (continued) (thousands of dollars)
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, 1996, 1995 and 1994. 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 U.S. reserves were $46,530,000 in 1996, $24,163,000 in 1995, and $25,006,000 in 1994. Discounted future net cash flows before income taxes for Canadian reserves in 1994 were $14,215,000. As required by SFAS-69, the tax computation 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 shown do not represent the expected lower future tax expense to the Company as 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, 1996 the U.S. oil price (including natural gas liquids) was $22.81 per barrel and gas price was $3.54 per thousand cubic feet. The SEC requires that this computation utilize year end product 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 use of prices that prevail on a single date can have an inordinate influence on its year-end reserves as well as on the resulting year to year change that a company reports for estimated discounted future net cash flows by the standardized measure calculation. Management has long advocated using weighted average of annual prices actually received to make this standardized measure calculation less susceptible to the impact of wide fluctuations in prices which have occurred so frequently in recent years. The use of a weighted average annual price may or may not be indicative of future cash flows depending on whether future average prices increase or decrease. This 1996 fiscal year is a good example of why the average price would be preferable since the year end prices for natural gas were higher than the average received during the year.
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 (SEC Case I) as of November 30, 1996, 1995 and 1994. The reports on the reserves of the properties located in the Berry Cox field in Texas were prepared by Huddleston & Co., Inc., another outside consulting firm. The reports are required in connection with the Company's bank line of credit.
Production
Columbus' net oil and gas production for each of the past three fiscal years is shown on the following table:
Fiscal Year ------------------------ 1996 1995 1994 ---- ---- ---- USA Oil-barrels 246,000 225,000 223,000 Gas-Mmcf .. 2,686 2,033 2,810
CANADA Oil-barrels -- 11,000 40,000 Gas-Mmcf .. -- 446 1,397 ------- ------- -------
TOTAL Oil-barrels 246,000 236,000 263,000 Gas-Mmcf .. 2,686 2,479 4,207
During the fiscal year 1996, 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 1995. This data was reported on a gross operated basis inclusive of royalty interest and, therefore, does not compare with Columbus' net reserves reported for 1995.
Average price and cost per unit of production for the past three fiscal years are as follows:
Fiscal Year 1996 1995 1994 ---- ---- ----
Average sales price per barrel of oil USA ............................... $19.42 $16.75 $15.28 Canada (U.S.$)(1) ................. -- 11.61 10.13 Total Company ..................... 19.42 16.48 14.47
Average sales price per Mcf of gas USA ............................... $ 2.15 $ 1.71 $ 1.92 Canada (U.S.$) .................... -- 1.09 1.39 Total Company ..................... 2.15 1.60 1.74
Average production cost per equivalent barrel USA ............................... $ 4.35 $ 4.16 $ 3.31 Canada (U.S.$) .................... -- 2.89 2.94 Total Company ..................... 4.35 3.99 3.20
Natural gas converted to oil at the ratio of six Mcf of natural gas to one barrel of oil. Production costs for fiscal years 1996, 1995 and 1994 include production taxes.
(1) Natural gas liquids are combined with oil.
Developed Properties
A summary of the gross and net interest in producing wells and gross and net interest in producing acres is shown in the following table:
November 30, 1996 Gross Net - ----------------- ----------------- ------------------- Oil Gas Oil Gas --- --- --- ---
Wells - USA 76 149 19 18
Acres - USA 34,218 9,435
Undeveloped Properties
The following table sets forth the Company's ownership in undeveloped properties:
November 30, 1996 Gross Acres Net Acres
Louisiana 31,565 3,946 Montana 7,802 4,806 New Mexico 840 630 North Dakota 3,750 1,615 Oklahoma 2,040 510 Texas 1,279 722 ------ ------
Total Undeveloped Properties 47,276 12,229 ====== ======
(a) Additional undeveloped leaseholds under option in Louisiana total 12,845 gross acres and 1,606 net acres.
Drilling Activities
The Company engages in exploratory and development drilling in association with third parties, typically other oil companies. Actual drilling operations are not conducted by the Company and are usually carried out by third party drilling contractors, but the Company may act as operator of the projects. The following table gives information regarding the Company's drilling activity in its last three fiscal years.
Year Ended November 30, ---------------------------------------------------------- 1996 1995 1994 --------------- -------------- --------------- Gross Net Gross Net Gross Net
EXPLORATORY Wells Drilled: United States Oil -- -- 1 .68 1 .09 Gas -- -- -- -- -- -- Dry 2 .68 -- -- 1 .68 Canada Oil -- -- -- -- 1 .33 Gas -- -- -- -- 1 .32 Dry -- -- -- -- 1 .50 DEVELOPMENT Wells Drilled: United States Oil 2 1.00 1 .19 -- -- Gas 14 2.60 8 .62 18 2.73 Dry 6 2.95 3 1.16 2 .34 Canada Oil -- -- -- -- 1 .33 Gas -- -- -- -- 3 1.46 Dry -- -- -- -- 2 .67 TOTAL Wells Drilled: Oil 2 1.00 2 .87 3 .75 Gas 14 2.60 8 .62 22 4.51 Dry 8 3.63 3 1.16 6 2.19 -- ---- --- ---- -- ----
Total 24 7.23 13 2.65 31 7.45 == ==== === ==== == ====
Current Activities
The Company concentrated on development of its properties and expanding its undeveloped acreage in Louisiana during fiscal 1996. Capital expenditures by the Company in the United States totaled $7,116,000 for development and exploration drilling and property acquisitions in the natural gas prone areas of Webb and Zapata counties near Laredo, Texas and in the Austin Chalk trend of midLouisiana.
A review of the more significant results follow below and has been segregated by Columbus' major areas of operations.
South Texas - Laredo Area
Though not its largest source of lease level cash income for the past several years, this area remains its single most important from an operational standpoint. The Company is operator of over 100 natural gas wells in various fields from the southern city limits of Laredo to the B.R. Cox field in Jim Hogg, County, almost 80 miles to the south.
Columbus owns working interests which range from 1% to 53% in all of the wells which it operates. One acquisition was closed in December which added small interests in a total of 107 mostly mature wells (6.2 net). This purchase was effective as of November 1, 1995 and daily production approximated 2,000 Mcf/d and 10 barrels of condensate per day. A similar acquisition of additional interests in 22 (3.9 net) producing wells in Webb and Zapata Counties, Texas was completed in June 1996. During 1996 a total of 12 gas wells were drilled in the Laredo area with 11 (1.3 net) successfully completed.
In the B.R. Cox field, a new operator conducted a minor recompletion program of new behind-the-pipe intervals in four wells during 1996. Two (0.5 net) attempts were successful and two (1.5 net) were uneconomic and the wells were abandoned. This recompletion program's lack of success was disappointing as has been Columbus' investment in this field almost from the beginning in 1994 when significant problems developed with the two initial wells drilled. Substantial cost overruns were encountered and eventually they were completed in intervals which were not the primary objectives. The likelihood of a satisfactory return ever occurring improved somewhat during 1996 as a result of higher prices and limited recompletion success.
Sralla Road Field Area - Harris County, Texas
This operational area has been Columbus' primary source of field level cash flow for the past several years and is expected to be reasonably important for a few more years. During the fourth quarter the Wiggins Unit #1 (78% WI) was completed in the upthrown fault block of the West Jackson Sralla Road oil field and extended the productive limits of its gas cap by almost one mile southwest. Logs indicated a similar thickness (about 6 feet) to other Jackson sand wells in the field, but appeared to have somewhat higher porosity which undoubtedly has contributed to the new well's capability of producing natural gas at rates several times its state-assigned allowable of about 1,400 Mcfd. However, even at this restricted flow rate it contributed an immediate 10% increase in Columbus' daily gas production following its connection in early November 1996. In addition, the Wiggins Unit #1 has been yielding approximately 35 to 40 barrels of condensate in conjunction with each Mmcf of gas produced since its connection.
Earlier during the first quarter 1996, a 160-acre unit was formed and the Brewer #2 (.66 WI) was completed as a high ratio oil well which extended this upthrown block field about 0.8 miles southwest of the Ferguson #1 oil discovery in October 1995. A third 160-acre drilling unit to the west of that discovery well was drilled during second quarter of 1996 but the Jackson sand was not present so that well bore was abandoned.
Williston Basin Area
The Company encountered equipment shortages and was forced to delay drilling plans for this area of its operations during 1996. However, a geologic study of certain fields in Montana and North Dakota was conducted in order to ascertain what workovers of current producing zones, recompletions of behind-the-pipe zones or possible horizontal drilling candidates could be justified. Also, the Company completed a 3-D seismic program early in the fourth quarter, aimed at locating the best structural well site to replace an existing 90%-owned 12,200 foot Red River oil well producer in the Southeast Froid field in Montana. This twin well is expected to be a substitute for the junked well bore which is located approximately 300 feet to the east and has been pumping for about ten years from a depth of only 7,600 feet due to a collapsed section of its 5 1/2 inch production casing at about 8,000 feet. Because Columbus was unable to contract for a large drilling rig during the fourth quarter, it had to postpone drilling the new well until January 1997. This replacement well is expected to drain the remaining Red River oil reserves in the field much more quickly while assuring that the Company can hold a substantial leasehold block for a few more years. During the first quarter of 1997 the McCabe 1-X twin well has been drilled, logged and cased and will shortly be completed in the Red River. Assuming no problem in obtaining a successful completion, it is proposed that the McCabe #1 Red River zone be abandoned and its cased well bore be utilized to produce from a potential uphole oil zone. This will require
cutting a window immediately above the collapsed interval and drilling in a side-tracked hole down to complete the Winnipegosis formation at about 11,000 feet and complete as an oil well there or in another prospective shallower interval if it proves unsuccessful. Crude oil was previously produced from that zone from an offsetting but structurally lower well. While conducting this 3-D seismic program the Company also encountered several leads which lend support to old 2-D seismic data which had indicated the possible existence of two or more separate Red River structures on this same acreage block. Based upon this new 3-D data, Columbus added several hundred more acres of new leases and has scheduled a supplemental 3-D seismic program for March 1997 jointly with another oil company. Columbus now holds a 90% working interest in about 2,000 acres of leaseholds immediately surrounding the Southeast Froid field which also overlie those potential new structures. Encouraged by the current oil price levels, Columbus fully expects that the Williston Basin in general, and this Southeast Froid field area in particular, will yield significant additions to its daily oil production during 1997. At $1 million for a successfully completed Red River oil producer and $600,000 for a 12,200-foot dry hole, these prospects will undoubtedly command a substantial part of the Company's drilling budget for at least the next year or two. Also, Columbus plans to drill shortradius laterals during 1997 in a few of its existing older Mission Canyon formation producers. Based upon the reported successes by other operators who have utilized this new technology, management has been encouraged that meaningful increases in daily oil production and reserves can be added as a result of this effort.
Oklahoma - Anadarko Basin
There were two (0.675 net) exploratory wells that resulted in dry holes although one had initially indicated a potential gas discovery until acidized, produced unacceptable rates of water along with the gas and had to be abandoned. A third well (0.3375 net) in this area was completed as a small oil producer. A fourth well was scheduled but drilling equipment delays postponed its drilling until the first quarter. It has apparently found Morrow formation oil production and is initially undergoing testing in one of its two prospective sand intervals.
Goudeau Prospect - Avoyelles & St. Landry Parishes, Louisiana
Columbus added an entirely new area of interest in late 1995 in mid-Louisiana when it joined with three co-venturers to promote the acquisition of leaseholds and the drilling of deep (15,500 feet vertical depth) wells, with single and dual horizontal extensions therefrom. The co-venturers formed a three township Area of Mutual Interest ("AMI") in the deep Austin Chalk trend in a known oil productive area. This was fortunately a few months prior to the time the leasing activity level began to accelerate as a result of several successful completions of high volume producers in new fields to the northwest of the AMI on a production trend extending west to the Texas border. The Company throughout fiscal 1996 continually emphasized the potential importance of this area beginning with its annual report and Form 10-K for the year ended November 30, 1995 published in March, 1996 and subsequently in each of its regular quarterly shareholder reports. A Special Interim Report to shareholders dated September 27, 1996 was specifically devoted to the Company's involvement in this prospect area and presented far more details than could possibly have been included in those prior reports.
Management has stated on several occasions that this new area offers the most potential to add sizable new oil reserves fairly quickly than any of its other core operating areas. This AMI is located in St. Landry and Avoyelles Parishes and the leaseholds are known to overlie a 250-foot zone of geo-pressured, fractured Austin Chalk. This onshore play has received extensive publicity recently in various trade publications because several dual lateral wells have been completed along that trend which were drilled 4,000 feet or more horizontally from vertical bore hole depths ranging from 14,000 to 17,000 feet. These high pressure completions have been large capacity natural gas/condensate and crude oil producers whose reported initial productivity tests have ranged from 2,000 to 6,000 barrels of oil or condensate per day along with 2.5 to 25 Mmcfd for some of those wells. A few uneconomic wells have also been recently drilled along this trend using up-to-date technology but these appear not to have dampened the enthusiasm of the principal operators in this new play as new locations and joint ventures have been announced fairly frequently during the past few months.
The Company and its three individual co-venturers had originally proposed to promote several companies' participation in a drilling program of at least two wells on our initially assembled block of issued and option leases consisting of approximately 24,000 acres. However, in the spring of 1996, a large independent operator, Belco Oil & Gas Corporation ("Belco"), agreed to acquire a 75% working interest in that block, agreed to accept the previously designated three township AMI, and then undertook to acquire substantial additional acreage on behalf of the group. Because of an intervening increase in acreage bonuses had occurred along the trend following the block's initial assemblage, the co-venturers (including Columbus for its 6.25%) realized a profit from Belco's acquisition of the base acreage block. The co-venturers were also to be carried by Belco for an after-payout 25% participation in a new well drilled from the grassroots to approximately 15,000 feet vertical depth with dual opposing laterals of about 4,000 feet each. Belco also undertook the group's prior farmout obligation to re-enter and drill a single lateral hole from a previously abandoned vertical cased wellbore within the AMI. This farmout had initially been acquired in order to have available a cased vertical well bore from which to test recent horizontal drilling technology and drilling fluids which the co-venturers had planned to utilize had they retained operatorship. After yielding that re-entry prospect to Belco, Columbus had no further participation rights and was relieved of incurring any expenses in the farmout.
Belco subsequently moved in a rig and completed that farmout re-entry well in August 1996. To date, it has made only one press release regarding that well's initial results in which it revealed a test having an initial flow rate of 2,500 BOPD and 2.7 Mmcfd from a single 3,900-foot lateral hole drilled horizontally from a 15,333 foot vertical depth. This test was conducted through a 1/2 inch choke with a flowing tubing pressure of 1,000 psi. No further official announcements have been made but industry press has speculated that the flow rate has declined fairly rapidly after being placed on production to about 200 barrels of oil per day.
As discussed in that Special Interim Report in September, Belco subsequently acquired additional leaseholds within the AMI over the summer which increased the block's total to more than 44,000 gross acres and 39,700 net acres. As of that report, Columbus owned varying interests from 6.25% to 12.5% under all issued leases and had a 6.25% interest in approximately 14,000 acres of leasehold options which are exercisable in 6-month intervals, in minimum options of 2,000 acres of newly issued leases, each having a 5-year term. Assuming all of those leasehold options are exercised over the next three years, Columbus and its co-venturers will not only have a fully paid up 25% participation in those newly issued leases but also will realize a profit of about $300,000 to each party.
As more fully described in Special Interim Report, Columbus' 12.50% working interest in the 16,000 gross acres within the AMI added by Belco could be reduced by 3.125% (to 9.375%) if one of the co-venturers exercised his option to acquire that interest at cost on or before October 28. The co-venturer in fact did timely exercise his option; however, on November 29, 1996, the Company paid $275,000 in cash and issued 30,000 shares of its Common Stock to acquire all of that co-venturers' interest throughout the AMI. This transaction brought Columbus' interest up to a uniform 12.50% throughout the assembled 44,000 acre block plus such other additionally acquired leaseholds yet to be identified or assigned by Belco estimated to be about 6,000 to 8,000 acres. The transaction also included the purchase of that co-venturer's 15% working interest in an existing vertical well bore completion in the Austin Chalk and his overriding royalty interests of approximately 1.3% and 1.6% in two existing Austin Chalk single lateral oil wells. The co-venturer retained his right to receive the $300,000 of future profits to be earned should Belco elect to exercise all of the remaining leasehold options.
It had been expected that Belco would have before year end commenced drilling the carried-interest grassroots dual lateral well. However, delays in receiving approval from government regulatory agencies for the surface location forced the deferral of contracting for a drilling rig. In order to speed up the timetable for commencement of operations, the co-venturers recently negotiated an amendment to Belco's original agreement related to the co-venturers' 25% carried working interest after payout in that grassroots well. The new arrangement basically spreads that undertaking over two wells by allowing for a portion of the
obligation to be satisfied by utilizing an existing vertical well bore owned by all parties which already has casing in place almost to the top of the Austin Chalk. This Morrow #1-23 well is located in Section 23 of Township 2 South Range 4 East around which a 1,960-acre rectangular unit has now been created which will permit acceptable length opposing dual laterals of about 4,000 feet each to be drilled by Belco. The Company and its co-venturers will be responsible for paying their 25% (12.5% to Columbus) share of the cost of re-entering the existing cased well bore, analyzing the integrity of the existing casing and adding a liner into the top of the Austin Chalk, if required. Thereafter, Belco, at its sole expense, will drill the two horizontal opposing lateral holes from this wellbore, run slotted liners in each, add production equipment in the vertical hole, and complete with surface equipment as appropriate. Columbus and its co-venturers will share in the initial revenues from this first well but only for a fraction of their regular 25% revenue stream that will be in a proportion which their respective costs incurred bears to total expenditures incurred by all parties in re-entering and placing the well into a productive status. Following recovery by Belco of its disproportionate share of the total well costs, the regular 25% working interest revenue stream will flow to Columbus (12.5%) and its co-venturers (12.5%) as opposed to the lower percentage of revenues received during the payout period.
A second well will be at the site of the originally selected grassroots well with its vertical wellbore located on the section line between Section 20 and 29 of Township 2 South, Range 5 East in the middle of a 1960-acre unit which will be declared for this well. A similar cost and percentage of revenue sharing approach will apply to this second well, except the roles essentially are reversed. That is, Belco will be responsible for paying all of the expenditures necessary to drill and case the well to a vertical depth of approximately 15,000 feet in preparation for the drilling of dual opposing lateral holes. At that point, the Company and its co-venturers will pay 25% of the expenses (one-half borne by Columbus) required to drill two laterals of approximately 4,000 feet, run slotted liners, and install downhole equipment and surface facilities required to place the well on production. Once again, Columbus and its co-venturers will realize only a portion of their regular 25% revenue stream during payout which is equal to a fraction determined by their share of expenditures as the numerator and the total of all expenditures by all parties as the denominator. When Belco has fully recovered its disproportionate costs, then the full 25% revenue stream will flow to Columbus (12.5%) and its co-venturers (12.5%).
Assuming one or both of the wells are successfully completed (as to which there can be no assurance), the length of the payout period for each of the wells will be dependent upon the total costs incurred, the initial completion rates achieved, and the rate of production decline thereafter. Initial completion rates are basically an outgrowth of and determined by the extent of the natural vertical fracturing encountered in the lateral segments of
these well bores. These fractures in turn will have a significant effect on the subsequent rate of productivity decline plus the eventual oil and natural gas reserves to be recovered from each well bore. Without actually drilling the holes, the frequency or size of fracturing which will be encountered in each of the horizontal laterals cannot be forecasted with any accuracy whatsoever although some companies are relying on seismic to help find areas where heavy fracturing is thought to be present. Therefore the Company cannot forecast the payout period for either of the two wells or to unequivocally state there will even be a payout in either well. However, based on performance of several wells recently completed in this same Austin Chalk interval along the trend to the northwest of the AMI, payouts could be as short as three to six months as have been experienced in those wells or in the case of others may recover only a small portion of their costs. Management expects that the success of these first two wells in the AMI will be similarly measured by not only the degree of fracturing encountered in the dual laterals but also on the ability of Belco to complete the wells without incurring costs in excess of budget. Should the development of the AMI prove only moderately successful and assuming Columbus participates in the 25 or so possible locations on its leaseholds that could be drilled over the next five years, this new prospect area possesses the potential to significantly increase Columbus' proved developed crude oil reserves. If these initial two tests prove unsatisfactory, the Company's share of costs should be no more than a dry hole Red River wildcat in its Montana program.
Management is confident that its leaseholds are located "on trend," since there have been numerous wells drilled in the past within this AMI that penetrated the Austin Chalk on the way to the deeper high pressure Tuscaloosa formation. Logs from those wells have exhibited a fairly uniform prospective zone of fractured Austin Chalk having about 250 feet in thickness. In fact, several wells encountered such severe fracturing while drilling the Austin Chalk interval that the wells were later completed in the zone using vertical well bores only. These completions occurred several years ago before present horizontal drilling technology was available. Some of those well bores are located on leases in which Columbus holds a working interest which could contribute to significant future cost savings from the drilling of one or more laterals from those well bores which had originally been cased to 15,000 feet or more.
Currently Belco has completed building location, the drilling rig has moved in and it has begun operations to re-enter the Morrow well in Section 23. Management believes that the delays in obtaining approval for the surface location of the second well should be overcome in time for the drilling of a well at that site shortly after completion of Morrow #1-23.
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.
All production of crude oil and condensate by the Company is sold to others at field prices posted by the principal purchasers of crude oil in the areas where the producing properties are located. In the Company's judgment, termination of the arrangements under which such sales are made would not adversely affect its ability to market oil and condensate at comparable prices. During recent years, the posted prices were directly affected by the fluctuations in the supply and price of imported crude oil as well as by trading of oil futures.
A very limited amount of the natural gas produced by the Company is being sold at the well head under long-term contracts. Because of deregulation of natural gas, recent excesses of domestic supply over demand, and the competition from alternate fuels caused Columbus, through CGSI, to take a much more active role in marketing its own gas, as well as gas owned by third parties.
Customers. Sales to three purchasers of crude oil and natural gas, which amounted to more than 10% of the Company's combined revenues for the years ended November 30, 1996, 1995 and 1994, are set forth in Note 3 to Notes to the Consolidated Financial Statements. In the opinion of management, a loss of a customer has not to date, and should not in the future, materially affect the Company since the nature of the oil and gas industry is such that alternative purchasers are normally available on very short notice.
Government Regulations
The development, production and sale of oil and gas is subject to various federal, state and local governmental regulations. In general, regulatory agencies are empowered to make and enforce regulations to prevent waste of oil and gas, to protect the correlative rights and opportunities to produce oil and gas between owners of a common reservoir, and to protect the environment. Matters subject to regulation include, but are not limited to, discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental protection. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas.
The Company believes that the environmental regulations, as presently in effect, will not have a material effect upon its capital expenditures, earnings or competitive position in the industry. Consequently, the Company does not anticipate any material capital expenditures for environmental control facilities for the current year or any succeeding year. No assurance can be 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.
Natural Gas Controls
The Federal Energy Regulatory Commission ("FERC") has issued several rules which encourage sales of gas directly to end users and provides open access to existing pipelines by producers and end users at the highest possible prices that can be negotiated. All price controls were terminated as of January 1, 1993. On April 8, 1992, FERC issued Order No. 636 which has essentially restructured the interstate gas transportation business. The stated purpose of Order 636 was to improve the competitive structure of the pipeline industry and maximize consumer benefits from the competitive wellhead gas market and to assure that the services non-pipeline companies can obtain from pipelines is comparable to the services pipeline companies offer to their customers. The Order is complex and, while it faces challenges in court, it has been fully activated following a rehearing with minimum modification and subsequent reissuance as FERC Order No. 636A. The Company is not able to predict the extent to which this very complex order will change the industry in the long term but short term it has led to much more competitive markets and raised serious questions about whether gathering systems of interstate pipelines can be sold off and totally escape regulation.
Item 3.

Item 3. LEGAL PROCEEDINGS
Management is unaware of any asserted or unasserted claims or assessments against the Company which would materially affect the Company's future financial position or results of operations.
The Company's officers and directors are indemnified by contractual agreement with each individual, as well as by the Articles of Incorporation of Columbus as provided in and in accordance with the Colorado Corporation Code, as amended, of the State of Colorado.
Item 4.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of 1996, no matters were submitted to a vote of security holders.
PART II
Item 5.

Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of Columbus commenced trading on the American Stock Exchange on March 11, 1993. The common stock previously traded on the American Stock Exchange Emerging Companies Marketplace since July 30, 1992, and on the Pacific Stock Exchange since April 15, 1988. The reported high and low sales prices for the periods ending below were as follows:
High(1) Low(1)
1997: December 1, 1996 through January 31, 1997 $11.00 $ 9.125
1996: First quarter $ 5.75 $ 5.00 Second quarter 8.00 5.375 Third quarter 11.375 7.00 Fourth quarter 10.875 9.50
1995: First quarter $ 8.07 $ 7.25 Second quarter 8.25 7.375 Third quarter 7.875 6.375 Fourth quarter 6.75 5.625
1994: First quarter $ 8.78 $ 7.75 Second quarter 9.32 8.41 Third quarter 8.75 8.41 Fourth quarter 8.52 7.95
(1) Price per share amounts have been adjusted for the 10% stock dividend distributions to shareholders of record on February 24, 1995 and March 2, 1994.
As of January 31, 1997 the reported closing sales price of Columbus common stock was $10.13 per share.
As of November 30, 1996, there were approximately 480 holders of record of Columbus' common stock and an estimated 1,200 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.
Item 6.

Item 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data of the Company and its consolidated subsidiaries for each of the years in the five-year period ended November 30, 1996, which information has been derived from the Company's audited financial statements. This information should be read in connection with and is qualified in its entirety by the more detailed information and financial statements under Item 8 below.
(a) Does not include results of CEC Resources Ltd. after its divestiture on February 24, 1995. (b) Reflects restated amounts for 1992 through 1994 after stock dividends. (c) No cash dividends have been declared or paid in any period presented. (d) See discussion of cash flows in "Management's Discussion and Analysis of Financial Condition and Results of Operations".
Item 7.

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.
Liquidity and Capital Resources
Columbus' financial condition continues to be very satisfactory. As 1996 closed, shareholders' equity was $16,225,000 after repurchase of 86,100 shares of treasury stock compared to $13,186,000 at November 30, 1995. Substantial positive working capital of $1,966,000 plus the Company's forecasted future cash flow remains a sufficient source of capital to develop its undeveloped reserves as well as fund a modest exploratory program. The $7,000,000 bank borrowing base of its credit facility has been designated by management for acquisitions of new oil and gas properties although the loan can be used for any legal corporate purpose.
Revenues for 1996 (without benefit of Canada) increased by 26% compared to 1995 (which did include three months of Canadian operations) while comparative U.S. only revenues increased by 37%. This was primarily the result of 64% higher natural gas revenues due to price and production increases. Net earnings of $2,098,000 or $.68 per share (primary) for 1996 compared to a net loss of $1,495,000, or $.48 per share, in 1995.
Generally, accepted accounting principles ("GAAP") require cash flows from operating activities to be presented. Net cash provided by operating activities has ranged from $4,000,000 to $6,000,000 during the last three years. Coupled with the available borrowing base under the Company's credit facility this has provided the liquidity required to finance oil and gas capital expenditures and make treasury stock repurchases. Management believes that another measure (commonly used in the industry although not "GAAP") of a company's cash flow is one determined before any consideration is given to working capital changes and without deduction of explora tion expenses. This is generally known as discretionary cash flow ("DCF") for successful efforts companies. DCF is important to present for successful efforts companies because under the full cost accounting method exploration costs are capitalized and do not affect operating cash flow. Exploration costs can be increased or decreased and DCF would still be comparable to cash flow of full cost companies. Columbus' DCF for 1996 was $6,658,000 compared to $4,096,000 in 1995 which 63% increase reflects higher natural gas and crude oil prices and production attained for the year. DCF is calculated before debt service. However, the Company's long-term debt does not require principal payments before July 1999 and interest expense on outstanding debt has been relatively insignificant each of the last three years.
Management takes strong exception with the Financial Accounting Standards Board Statement No. 95 which directs that operating cash flow should be determined after consideration of working capital changes and reflects its position on this matter in all of its public filings and reports. Such a requirement ignores entirely the significant impact on working capital, including the timing of income received for and expenses incurred on behalf of third party owners in wells, where a company such as Columbus serves as an operator of properties with only a small working interest.
Both discretionary cash flow and operating cash flow before working capital do not represent cash flows as defined by GAAP and are not to be substituted for net income or cash available from operations and do not necessarily indicate that cash flows are sufficient to fund all cash requirements.
The Company's U.S. sales volume of natural gas averaged 7,927 Mcfd during fourth quarter of 1996 was up 17% from 1995's average of 6,792 Mcfd. Management's 1996 goal had been to surpass the former record of 2,200 barrels of oil equivalent per day benchmark attained for U.S. production during the 1994's third quarter but was unsuccessful although for the month of November, 2,059 BOE per day was reached.
During 1994, Columbus hedged natural gas prices by selling a "swap" of 100,000 Mmbtu per month for the twelve month period from May 1994 through April 1995 at an average daily price of $2.12 per Mmbtu. The swap was matched against the calendar monthly average price on the NYMEX and settled monthly resulting in an increase in revenues of $204,600 for the period from May through November 1994 and an increase in revenues of $283,900 during fiscal 1995 before its expiration in April 1995.
The Company subsequently entered into two new natural gas swaps by selling 60,000 Mmbtu per month for the period from April 1996 through November 1996 with one at $1.74 per Mmbtu and a second at $1.88 per Mmbtu. These volumes represented approximately 65% of Columbus' gas production at the time. To partially protect itself against possible escalating gas prices for October and November 1996, the Company purchased NYMEX futures contracts for those two months for 60,000 Mmbtu of natural gas at $1.805 and $1.875, respectively. The October call contract was sold for a profit of $37,500 in June 1996 and the November call option was sold for $4,500 in September 1996. These partially offset losses from the swaps for those months. For the eight month period, gas sales revenues were reduced by $560,000 as a result of the swaps because the market price at settlement exceeded the contract swap price.
Columbus also entered into a swap of crude oil prices by selling 10,000 barrels per month for the twelve month period from January 1996 through December 1996 at an average daily price of $17.25 per barrel with a cap of $19.50 as upside protection should crude oil futures soar for an unseen reason. This volume represented approximately 50% of its then current monthly production. The difference between the hedge price and the actual daily closing price on the NYMEX was settled monthly. Through November 1996 the swap reduced oil revenues by $232,000 with another $22,500 deducted for December 1996 because the market price at settlement exceeded $19.50 per barrel.
Columbus entered into another crude oil swap by selling a strip of 10,000 barrels per month for the twelve month period from November, 1996 through October, 1997 at an average daily price of $21.17 per barrel. This amount represents approximately 50% of Columbus' current crude oil production. A loss of $24,000 was incurred for the month of November 1996. Also, Columbus entered into a natural gas swap by selling 60,000 Mmbtu per month for the period from March 1997 through October 1997 at $2.20 per Mmbtu. This volume represents about 20% of Columbus' current natural gas production.
The Company's natural gas and crude oil swaps are considered financial instruments with off-balance sheet risk which were in the normal course of business to partially reduce its exposure to fluctuations in the price of crude oil and natural gas. Those instruments involve, to varying degrees, elements of market and credit risk in excess of the amount recognized in the balance sheets. As calculated as of November 30, 1996, the Company had 1997 natural gas and crude oil swaps with a notional value of approximately $3,557,000 and a market value of approximately $3,424,000. The market value changes constantly and over the term of the contracts could even result in a gain for the Company. Should the price of crude oil and natural gas futures remain above the swap price each month, then the Company revenues would be reduced. In the case of crude oil for calendar year 1996, the Company capped that exposure.
Columbus' average daily rate of oil production (U.S. only) for 1996 was 9% more than 1995.
The Company's operation and management services segment remains profitable despite divesting the principal source of past profit generated in Canada from processing fees.
Columbus had outstanding borrowings of $2,200,000 as of November 30, 1996 against its line of credit with Norwest Bank Denver, N.A. having a borrowing base which was lowered in 1995, at the request of the Company, to $7,000,000. The credit is collateralized by oil and gas properties. At the end of 1996, the ratio of bank debt to shareholders' equity was 0.14 and to total assets was 0.10. The debt outstanding used a LIBOR option at an interest rate of 6.9%. Subsequent to year end through February 15, 1997, the debt was further reduced by $600,000 to $1,600,000. The net increase or decrease in long-term debt directly affects financing activities cash flow. This cash flow item also reflects the purchase of treasury stock discussed below and benefits from the proceeds from the exercise of stock options.
Working capital at 1996 year end remained positive at $1,966,000 compared to $1,941,000 at November 30, 1995. This was achieved despite expenditures of $7,116,000 (including $3,510,000 for acquisitions) for new additions to U.S. oil and gas properties as well as the purchase of 86,100 shares of treasury stock for $579,000 during the year.
In February 1995 a 300,000-share repurchase from the market was authorized and was restricted to a maximum price of $8.75. These could be purchased from time to time during 1995, 1996 and beyond out of available cash but not using bank borrowings. Through January 1997, the Company acquired 284,000 shares of that total, including 1996's 86,100 shares, at an average price of $7.12 per share.
During 1996, capital expenditures incurred on oil and gas properties totaled $7,116,000 for acquisitions and development drilling and recompletions primarily in the South Texas and Gulf Coast areas. This amount differs from the capital expenditure shown in the Consolidated Statement of Cash Flows which includes cash payments made during 1996 for 1995 expenditures incurred but not yet paid as of 1995's year end. Similarly, there have been expenditures accrued in 1996 that will not be actually paid until 1997. Therefore, that Statement's reported capital expenditure total is somewhat meaningless and amounts to little more than an accounting for bills paid during a given period. The cash flows from investing activities benefited in 1995 by the $4,075,000 net proceeds received from the divestiture of Resources.
Results of Operations
It should be obvious that 1996 revenues and expenses are not entirely comparable to 1995 because of the aforementioned divestiture of the Canadian subsidiary toward the end of the first quarter of 1995. Total Company revenues increased by 26% in 1996 and if Canadian operations are excluded from 1995, the Company's revenues increased by 37%. Higher crude oil and natural gas prices and production are responsible. The Company's revenues decreased by 28% in 1995 compared to 1994 but only by 15% if Canadian operations are excluded.
Operating income increased to $3,589,000 in 1996 due to improved revenues compared to 1995's loss of $1,811,000, which was affected by the impairment losses discussed below. The operating loss in 1995 was caused by the lower revenues and higher depletion expense. Even without Canadian operations and impairment losses included, 1995 operating income decreased 57% from 1994.
The table included below in "Oil and Gas Operations" reflects the changes in both U.S. and Canada for the important areas of revenue, production and prices.
The Company had record revenues in 1994 but operating income decreased 9% from 1993's results, which itself had been a record. Litigation expenses in 1994 were mostly related to two settled lawsuits. Interest expense rose in 1994 because of increased interest rates and amounts borrowed compared to 1993 which had decreased as rates and average bank borrowings declined. Net earnings in 1995 (before impairment charge) were at their lowest level since 1991. Net earnings in 1994 did not match 1993's for reasons previously discussed but a quick reiteration of those include increased exploration expense, litigation expense, interest expense, depreciation and depletion charge, and a higher effective tax rate.
Impairment of Long-Lived Assets
The Company elected to adopt early as of the beginning of the fourth quarter of 1995 Statement of Financial Accounting Standards No. 121 ("SFAS-121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". SFAS-121 requires that an impairment loss be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flow of the asset. The Company reviewed impairment of oil and gas properties using expected prices and year end proved reserves which had been significantly reduced. Four areas in Texas, Oklahoma, New Mexico and North Dakota indicated that impairment losses were greater than previously estimated and that it was prudent to elect early adoption. Accordingly, a non-cash loss of $3,055,000 ($2,260,000 after tax) was recognized which was equal to the difference between the carrying value and the fair value of each asset group. As a result of the adoption of SFAS-121 future amortization and depletion expenses were expected to be lower since the total carrying value has been significantly reduced.
Prior to September 1, 1995, a valuation provision was made if total capitalized costs of oil and gas properties, excluding unproved properties, by country, exceeded (1) the present value of future net revenues from estimated production of proved oil and gas reserves using constant prices discounted at 10% less (2) income tax effects related to differences between book and tax basis of the properties. Therefore, no impairment was necessary prior to adopting SFAS-121 because total capitalized costs in the U.S. were far less than discounted future net revenues.
During 1996 an additional impairment of $165,000 was made for the Oklahoma area because of abandonment of a new well drilled which caused the capitalized costs to again exceed the fair value in that area.
Oil and Gas Operations
The following discussion of the Company's oil and gas operations is based upon the tables of production and average prices shown separately for the United States and Canada. See Item 2, "Oil and Gas Properties" and "Production".
The changes in the components of oil and gas revenues during the periods presented are summarized as follows:
Production Price Change Quantity Change Revenue Change
1996 vs. 1995 Gas - U.S. 26 % 32 % 64 % Gas - Canada - % (100)% (100)% ------- ------- ------- Total Company gas 26 % 8 % 44 %
Oil - U.S. 16 % 9 % 28 % Oil - Canada - % (100)% (100)% ------- ------- ------- Total Company oil 16 % 4 % 23 %
1995 vs. 1994 Gas - U.S. (11)% (28)% (33)% Gas - Canada (22)% (68)% (75)% ------- ------- ------- Total Company gas (8)% (41)% (45)%
Oil - U.S. 10 % 1 % 8 % Oil - Canada 15 % (72)% (67)% ------- ------- ------- Total Company oil 14 % (10)% 0 %
Natural gas revenues in the U.S. increased 64% (despite reductions from swaps) for 1996 compared to 1995 as a result of 26% higher prices and 32% increase in production. Average prices for natural gas rose with increased demand and severely depleted storage levels following an extended 1995/1996 winter heating season. Reported 1996 natural gas revenues were reduced by $518,000 ($.19 per Mcf) from swaps of natural gas while 1995 had increased revenues of $284,000 ($.14 per Mcf). Production volumes increased as a result of additional interests from property acquisitions and the effect of newly developed wells. Average prices in the spot market remain quite high during 1997's first quarter due to very cold winter weather and low storage.
Oil revenues in the U.S. for 1996 were up 28% from last year as a result of a 16% increase in the average price received and 9% higher volumes. Oil revenues and average prices for 1996 have been reduced by $256,000 ($1.04 per barrel) due to hedging losses. The Company had no oil hedges in 1995. Crude oil production improved because of two new Jackson sand oil wells in the Sralla Road field and a third discovery (78% WI) almost one mile southwest which commenced production in November 1996. These increases were sufficient to overcome normal production decline elsewhere.
Natural gas revenues and production for 1995 decreased compared to 1994 primarily as a result of lower prices, lower gas production in the Sralla Road field, and a reversionary interest in the Company's most productive gas well in the Laredo area which accounted for about one-half of the reduced gas production. These more than offset new production from additional well connections in Texas and Oklahoma, Average prices for natural gas decreased 11% compared to 1994 but began to increase toward the end of fiscal 1995.
Oil revenues for the U.S. for 1995 were up 8% from 1994 as a result of a 10% increase in the average price received. In 1995 low crude oil prices dictated continued deferral of any full scale oil development program of undeveloped oil reserves located in the Williston Basin. However, a moderate amount of drilling was planned for 1996 as a result of the 1996 oil swap. This at least afforded some protection from previous drastic downturns in prices which had halted drilling plans before anything could be commenced.
U.S. natural gas revenues and production for 1994 were significantly higher than 1993 because of new gas well completions in Texas and Oklahoma. Even with the inclusion of the unusual revenue gains from the 1994 natural gas swap, the average price realized in 1994 still decreased by 12% compared to 1993. The Company experienced normal decline in oil production in 1994, but a few wells, which had been made uneconomic by oil prices and whose production had been curtailed awaiting improvement in oil prices, were returned to production during fourth quarter of 1994. Also, the flooding of a river near Houston in late 1994, which required shutting-in several wells, was primarily responsible for a drop in oil production of 77 barrels per day compared to the 1994 average and resulted in a reduction in gas production of 2,100 Mcfd for the fourth quarter of 1994, compared to 1994's third quarter.
U.S. oil prices have fluctuated for several years with the same wide swings experienced in world crude oil price. In 1994 there was a very slow recovery with the average price for the year about 13% below 1993. In 1995 crude oil prices declined during mid-year months but recovered by year-end so that the average annual prices were higher than 1994. In the spring of 1996 crude oil prices rose quickly to above $20 per barrel, declined briefly, then rose rapidly to almost $23 per barrel by year end.
Fluctuations of oil and gas revenues and operations in Canada are consistent with the spin-off of Resources in February 1995, i.e. 1995 vs. 1994 revenues decreased 75% which reflects the fact 1995 included only one quarter of Canadian activity. Similarly, lease operating costs declined when comparing 1995 to 1994.
Lease operating expenses in the U.S. increased 23% in 1996 compared to 1995 because of incremental working interest acquisitions and several extensive work-overs performed in an effort to make some wells more economic. Lease operating costs on a barrel of oil equivalent basis for 1996 were up slightly to $2.80 compared to $2.78 for 1995. Lease operating expenses in the U.S. increased 19% in 1995 compared to 1994 because of a few expensive work-overs. Lease operating costs on a barrel of oil equivalent basis for 1995 were up to $2.78 compared to $1.93 for 1994. Lease operating expenses in the U.S. had decreased 7% in 1994 compared to 1993 because of fewer workovers and because several oil wells with high operating costs were shut in due to low crude oil prices. Also, most new well additions in 1994 were gas wells which usually have lower operating costs. Operating costs in the U.S. as a percentage of revenues decreased to 19% in 1996 due to higher unit prices. This compares to 22% in 1995 and 15% in 1994.
Production and property taxes have approximated 10% of revenues in 1996 and 1995 and varies somewhat annually based on production in Texas where oil production tax rates are lower than gas production tax rates. In the U.S. the relationship of taxes and revenue is not always directly proportional because some local jurisdiction's taxes are based upon reserve evaluations as opposed to actual revenues or production for a given period.
Operating and Management Services
This segment of the Company's U.S. business is comprised of operations and services conducted on behalf of third parties and includes compressor rentals.
In 1996, a profit of $210,000 was generated from this segment. Prior to the Company's divestiture of Resources, the Company received significant operating service revenue from its share of processing fees at the Carbon area liquid extraction plant. Those revenues also included fees from the processing of Resources' own gas, but no profit was generated from that portion of revenues since it was offset by a commensurate increase in Columbus' well operating expenses.
Operating and management services U.S. revenue has increased each of the last three years. Until divested in 1995, Canadian operations had contributed far greater operating margins but 1995 revenues in the U.S. improved because of additional billings for operator services related to 3-D seismic testing program and past audit adjustments. These factors generated a $199,000 profit for the U.S. segment compared to a $197,000 profit in 1994.
Specific amounts of reimbursed revenues from operating and management services received from formerly operated partnerships are disclosed in Note 7 of the Notes to the Financial Statements.
Interest Income
Interest income is earned primarily from short-term investments whose rates fluctuate with changes in the commercial paper rates and the prime rate. Interest income decreased in 1996 to $125,000 compared to $160,000 in 1995, primarily as a result of a decreased amount of investments and lower short-term interest rates. The increase in interest income in 1995 over 1994 was primarily the result of an increase in the amount of investments early in the year (after divestiture of Resources) and higher short term interest rates.
General and Administrative Expenses
General and administrative expenses are considered to be those which relate to the direct costs of the Company which do not originate from operation of properties or providing of services. Corporate expense represents a major part of this category although other nonbillable expenses are included herein.
The Company's 1996 expenses were lower compared to 1995 because of salary and staff reductions made in August 1995. Also, incentive bonuses (all non-cash) totaled only $83,000 in 1996 compared to $110,000 in 1995.
Reimbursement for services provided by Columbus officers and employees for managing Resources for fiscal 1996 had been expected to decrease in anticipation that Canadian-based management would take over following a business combination with another junior oil and gas company. However, merger discussions were placed on hold in September due to an indicated oil discovery by Resources that could require a substantial evaluation period. Columbus' general and administrative expense will increase when Resources' merger occurs in 1997 since no further staff reductions are planned. Reimbursement of $296,000 was realized in 1996 and $281,000 for all of fiscal year 1995 for providing these services to Resources.
The Company's U.S. only expenses for 1995 were 6% higher than 1994's because employee salary and staff reductions were offset by higher compensation from cashless stock option exercises, increased fees associated with a regular listing on the Amex, shareholder and stock transfer expense, professional services (which included the fees of a second petroleum engineering firm) and a higher matching percentage contribution to the Company's 401(k) Plan. Expenses for 1994 were higher than 1993 because of employee salary increases plus incentive bonuses of $111,000 that were awarded to all officers based on achievements of the Company in 1993. Also, employees had higher medical claims under the Company's self-insured plan and the Company made a higher matching contribution to its 401(k) Plan. Overall, the total of general and administrative expenses declined in 1995 compared to 1994 due to the spin-off of Resources.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are calculated based upon the units of production compared to proved reserves of each field. The expense is not only directly related to the level of production, but also is dependent upon past costs to find, develop and recover those reserves. Depreciation and amortization of office equipment and computer software is also included in the total charge.
Total charges for depletion expense for oil and gas properties increased in 1996 over 1995 due to greater production despite the benefit realized from the 1995 write-down of the carrying value of certain properties upon adoption of SFAS 121. During 1995 and 1994, depletion expense for oil and gas properties increased by greater percentages than the increase in production. Contributing to the disproportionately higher depletion expense were much lower gas and crude oil prices during 1995 and 1994, which tended to reduce reserves, shorten the estimated reserve life and change the economic limits of certain of the Company's properties. The lower carrying values of certain oil and gas properties after the impairment loss with the adoption of SFAS 121 effective September 1, 1995 helped to reduce depletion expense for the fourth quarter of 1995.
For 1996 the depletion and depreciation rate for the Company was $3.86 per barrel of oil equivalent compared to $3.83 per barrel of oil equivalent for fiscal 1995 and $2.78 per barrel of oil equivalent in 1994. These amounts are still below the industry average primarily because of historically low finding costs. However, without including the benefit of lower depletion costs of Canadian gas properties for one quarter, the higher cost U.S. additions would have raised the 1995 charge to $4.21 per barrel of oil equivalent.
During 1994 the Company wrote-down U.S. oil and gas properties that had been fully depleted in previous years totaling $17,342,000 as a charge against accumulated depreciation, depreciation and amortization. There was no gain or loss to the Company because the properties had been fully depleted.
Exploration Expense
In general, the exploration expense category includes the cost of Company-wide efforts to acquire and explore new prospective areas. Until Resources was divested in February 1995, the Company's exploration expense was primarily attributable to geological consulting work provided in Canada plus limited seismic expense in Canada and the U.S. The successful efforts method of accounting for oil and gas properties requires that the cost of drilling unsuccessful exploratory wells and other exploratory costs be currently expensed.
During 1996 two exploratory wells drilled in Oklahoma proved noneconomic and $184,000 was expensed. Most of the balance of the 1996 expense was for geological consulting. During 1995, seismic survey costs of $46,000 were incurred in Canada and expensed while undeveloped leasehold costs in North Dakota were impaired by $69,000 both of which contributed to an exploration expense of $245,000. In 1994 two unsuccessful exploratory wells were drilled at a net cost to the Company of $307,000, including one in Saskatchewan, Canada and one in Harris County, Texas, about two miles west of the Sralla Road field. The Texas well also condemned certain leaseholds, while the Company allowed other leases to expire. Altogether these resulted in an additional charge of $202,000. These exploration expenses reduce reported cash flow from operations, in addition to net earnings, even though they are discretionary expenses; however, these charges are added back for purposes of calculating discretionary cash flow.
Retirement and Separation Expense
During 1995 a total of $32,000 separation expense was paid to employees whose positions were eliminated and a total of $109,000 was accrued for retirement compensation for past years' service for two employees who reached age 65 and were approved by the Board of Directors to receive such compensation.
Litigation Expense
The litigation expenses in 1995 and 1994 related to two lawsuits previously discussed in detail in prior Annual Reports. The first, Michael Mattalino, Bruce L. Davis and Maris E. Penn vs. Columbus Energy Corp. filed on April 23, 1993 was settled by agreement in September 1994. The second, Porter Farrell II vs. Columbus Energy Corp. filed October 14, 1993 had Columbus' motion for summary judgment granted on April 12, 1995 and the lawsuit was dismissed.
Interest Expense
Interest expense varies in a direct proportion to the amount of bank debt and the level of bank interest rates. The average bank interest rate paid for U.S. debt in 1996, 1995 and 1994 was 7.2%, 7.9%, and 5.9%, respectively.
Income Taxes
The Company's income tax position is somewhat complex. Resources' income was consolidated with the Company's U.S. income until Columbus' divestiture of Resources in 1995. Also, the utilization of net operating loss carryforwards by the Company has been complicated by two "change of ownership" transactions under Section 382 of the Internal Revenue Code, one of which occurred on October 1, 1987 and the other on August 25, 1993. Only the first of those changes is expected to limit the utilization of net operating loss carryforwards. Furthermore, a quasi-reorganization occurred on December 1, 1987 which requires that benefits from net operating loss carryforwards or any other tax credits that arose prior to the quasi-reorganization be credited to additional paid-in capital rather than to income. Only post quasi-reorganization tax benefits realized can be credited to income.
As a result of available net operating loss carryforwards, the Company's Federal income tax obligations have been limited to "alternative minimum tax" so that the Company has had a current Federal tax payable of less than 2% of pre-tax earnings. Beginning in 1997, the Company expects that the only operating loss carryforwards remaining will be from periods prior to the first Section 382 ownership change. Utilization of those benefits are limited to $904,000 per year so that the Company's current Federal tax provision and liability may increase in 1997 and thereafter unless an active drilling program is maintained. In addition, the Company pays state income taxes and previously, until its divestiture, also included Canadian taxes on Resources' income.
As of November 30, 1994, additional carryforward tax benefits were considered realizable and the post quasi-reorganization valuation allowance was reduced by $303,000. A deduction of $29,000 for disqualifying disposition of incentive stock options was taken and was added to additional paid-in capital along with $182,000 for the reduction in the pre quasi-reorganization valuation allowance. The 1994 effective income tax rate increased because of higher Canadian deferred taxes. No tax credit for U.S. income taxes was available to offset the effect of payment of Canadian taxes.
During 1995, the U.S. net deferred tax asset was reduced to $638,000 which is comprised of a $1,290,000 current deferred tax asset and a $652,000 long-term tax liability. The deferred tax asset increased by an estimated $537,000 during 1995. The valuation allowance was increased by a net $96,000 even after Canadian deferred taxes were reduced by $233,000 since such a provision was no longer required following the divestiture. The estimated effective tax rate for 1995 was a 26% book benefit.
During 1996, the net deferred tax asset was reduced to $1,000 which is comprised of $631,000 current deferred tax asset and $630,000 long-term liability. The valuation allowance had a net reduction of $268,000 from 1995 to November 30, 1996. A deduction of $102,000 for the benefit of disqualifying disposition of incentive stock options added to additional paid-in capital.
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 will be affected by any recurrence of such economic conditions. Recently, inflation has had a minimal affect on the Company.
In recent years, oil and natural gas prices have fluctuated widely so the Company's results of operations and cash flow have been directly affected. Oil and gas prices have also been significantly influenced by regulation by various governmental agencies, by the world economy, and by world politics. Operating expenses have been relatively stable but, when analyzed as a percentage of revenues, may be distorted because they become a larger percentage of revenues when lower product prices prevail. Drilling and equipment costs have risen noticeably in the last year. Competition in the industry can significantly affect the cost of acquiring leases, although in the past decade competition has lessened as more operators have withdrawn from active exploration programs. Inflation, as well as a recessionary period, can cause significant swings in the interest rates the Company pays on bank borrowings. These factors are anticipated to continue to affect the Company's operations, both positively and negatively, for the foreseeable future.
Item 8.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The report of independent accountants and consolidated financial statements listed in the accompanying index are filed as part of this report. See Index to Consolidated Financial Statements on page 42.
Item 9.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Items 10 and 11. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION
A definitive proxy statement related to the 1997 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 1997 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 1997 Annual Meeting of Stockholders and is incorporated herein by reference.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page (a) Financial statements and schedules included in this report:
See "Index to Consolidated Financial Statements"..................... 42
All schedules are omitted since either the required information is set forth in the financial statements or in the notes thereto or the information called for is not present in the accounts or is not required under the exception stated in Rule 5.04.
(b) Reports on Form 8-K:
The following reports on Form 8-K were filed on behalf of the Registrant since the third quarter of fiscal 1996:
None
(c) Exhibits:
Exhibit No. * 3(a) Restated Articles of Incorporation and Amendments thereto to date (Exhibit to Registration Statement No. 33-17885, Exhibit "a" to Form 10-Q dated July 13, 1990 and Exhibit 3(1)(a) to Form 8-K dated May 11, 1995).
* 3(b) Amended By-Laws of Columbus Energy Corp. amended as of October 18, 1994 (Exhibit to Form 8-K dated October 20, 1994) and as of February 13, 1995 (Exhibit to Form 8-K dated February 16, 1995).
*10(a) Amended and Restated Credit Agreement dated as of October 23, 1996 between Columbus Energy Corp. and Norwest Bank Denver, National Association (Exhibit 10(a) to Registration Statement No. 333-19643 dated January 13, 1997).
*10(b) 1993 Stock Purchase Plan (Exhibit to Registration Statement No. 33-63336).
*10(c) 1995 Stock Option Plan (Exhibit 10(k) to Form 8-K dated May 11, 1995).
*10(d) 1985 Stock Option Plan (Exhibit to Registration Statement No. 33-17885).
*10(e) 1985 Stock Option Plan, Amendment No. 2 dated November 7, 1991 (Exhibit 10(h) to Form 10-K dated November 30, 1991).
*10(f) Separation Pay Policy adopted December 1, 1990 for officers and employees and as amended February 17, 1992 (Exhibit 10(i) to Form 10-K dated November 30, 1991).
*10(g) Form of Indemnity Agreements with directors (Exhibit 10(k) to Registration Statement No. 33-46394).
11 Statement of computation of per share earnings.
22 Subsidiaries of the Registrant.
23(a) Consent of Coopers & Lybrand L.L.P.
23(b) Consent of Reed W. Ferrill & Associates, Inc.
23(c) Consent of Huddleston & Co., Inc.
27 Financial Data Schedule
- --------------- *Incorporated by reference
COLUMBUS ENERGY CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
Report of Independent Accountants ...................................... 43
Financial Statements: Consolidated Balance Sheets at November 30, 1996 and 1995 .......................................... 44
Consolidated Statements of Operations for the years ended November 30, 1996, 1995 and 1994 ........................ 46
Consolidated Statements of Stockholders' Equity for the years ended November 30, 1996, 1995 and 1994 .................................... 48
Consolidated Statements of Cash Flows for the years ended November 30, 1996, 1995 and 1994 ........................ 50
Notes to the Consolidated Financial Statements ......................... 51
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Columbus Energy Corp.
We have audited the accompanying consolidated balance sheets of Columbus Energy Corp. and subsidiaries as of November 30, 1996 and 1995, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended November 30, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Columbus Energy Corp. and subsidiaries as of November 30, 1996 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended November 30, 1996, in conformity with generally accepted accounting principles.
As explained in Note 2 to the consolidated financial statements, effective September 1, 1995, the Company changed its method of accounting for the impairment of long-lived assets.
COOPERS & LYBRAND L.L.P.
Denver, Colorado February 11, 1997
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
November 30, ------------------------- 1996 1995 ---- ---- (in thousands)
Current assets: Cash and cash equivalents $ 1,396 $ 1,414 Accounts receivable: Joint interest partners 889 1,258 Oil and gas sales 1,544 817 Less allowance for doubtful accounts (116) (116) Deferred income taxes (Note 6) 631 1,290 Inventory of oil field equipment, at lower of average cost or market 115 76 Other 77 85 ------- -------
Total current assets 4,536 4,824 ------- -------
Property and equipment: Oil and gas assets, successful efforts method (Notes 3 and 5) 28,031 22,244 Other property and equipment 2,001 2,028 ------- -------
30,032 24,272
Less: Accumulated depreciation, depletion, amortization and valuation allowance (Notes 2 and 3) (12,943) (10,775) -------- -------
Net property and equipment 17,089 13,497 -------- -------
$ 21,625 $18,321 ======== =======
(continued)
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
November 30, ------------------- 1996 1995 ---- ---- (in thousands)
Current liabilities: Accounts payable $ 1,292 $ 1,314 Undistributed oil and gas production receipts 54 348 Accrued production and property taxes 555 635 Prepayments from joint interest owners 258 189 Accrued expenses 348 318 Income taxes payable (Note 6) 33 - Other (Note 4) 30 79 ------- ------
Total current liabilities 2,570 2,883 ------- ------
Long-term bank debt (Note 5) 2,200 1,600 Deferred income taxes (Note 6) 630 652
Commitments and contingent liabilities (Notes 4, 7, and 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; 3,499,915 shares issued in 1996 and 3,328,580 in 1995 (outstanding 3,155,346 in 1996 and 3,068,149 in 1995) (Notes 1 and 8) 700 666 Additional paid-in capital 17,361 15,842 Retained earnings (accumulated deficit) since December 1, 1987 (Note 2) 720 (1,378) ------- ------- 18,781 15,130 Less: Treasury stock, at cost (Note 8) 344,569 shares in 1996 and 260,431 shares in 1995 (2,556) (1,944) ------- ------- Total stockholders' equity 16,225 13,186 ------- ------- $21,625 $18,321 ======= =======
The accompanying notes are an integral part of these consolidated financial statements.
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
(continued)
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS - (continued)
The accompanying notes are an integral part of these consolidated financial statements.
COLUMBUS ENERGY CORP. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY For The Three Years Ended November 30, 1996
(continued)
COLUMBUS ENERGY CORP. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - (continued) For The Three Years Ended November 30, 1996
The accompanying notes are an integral part of these consolidated financial statements.
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(1) FORMATION AND OPERATIONS OF THE COMPANY
Columbus Energy Corp. ("Columbus") was incorporated as a Colorado corporation on October 7, 1982 primarily to explore for, develop, acquire and produce oil and gas reserves. Columbus' wholly-owned subsidiary is Columbus Gas Services, Inc. ("CGSI"). CEC Resources Ltd. ("Resources") was also a wholly-owned subsidiary prior to February 24, 1995 when it was divested by Columbus by a rights offering to its shareholders (see below). Columbus and its subsidiary are referred to in these Notes to the Financial Statements as the "Company".
On February 24, 1995, Columbus completed a rights offering to the Columbus shareholders to purchase one share of Resources at U.S.$3.25 cash plus two subscription rights. One right was distributed as a dividend for each share held of record on January 27, 1995. All 1,500,000 shares of Resources common stock were subscribed (and oversubscribed) and yielded an aggregate of $4,875,000 before deduction of Resources' cash of $674,000 and $126,000 for the costs of the offering. At the date of divestiture Resources' book assets totaled $5,434,000 and liabilities were $977,000 with $874,000 cumulative foreign currency loss in equity. The total value assigned to the rights on its books was $582,000 for the dividend portion of the purchase of Resources shares. No gain or loss can be recognized for book purposes in a spin-off. The combination of the cash offering price of $3.25 per share plus the value of the rights dividend assigned was equal to the U.S. historical book cost of Columbus' investment in Resources. The divestiture was the sale of a foreign subsidiary engaged in the same business as Columbus. No taxes were due Revenue Canada as a result of this divestiture of common stock because the tax basis exceeded the proceeds received upon disposition.
(2) ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles and require the use of managements' estimates. The following is a summary of the significant accounting policies followed by the Company.
Consolidation
The accompanying consolidated financial statements include the accounts of Columbus and its wholly-owned subsidiaries, CGSI and Resources through February 24, 1995. All significant intercompany balances have been eliminated in consolidation.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Cash Equivalents
For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Hedging activities are included in cash flow from operations in the cash flow statements.
Oil and Gas Properties
The Company follows the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) for expenditures relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense in the year incurred. Dry hole costs incurred on exploratory operations are expensed. Dry hole costs associated with developing proved fields are capitalized. Expenditures for additions, betterments, and renewals are capitalized. Exploratory geological and geophysical costs are expensed when incurred.
Upon sale or retirement of proved properties, the cost thereof and the accumulated depreciation or depletion are removed from the accounts and any gain or loss is credited or charged to income if significant. Abandonment, restoration, dismantlement costs and salvage value are taken into account in determining depletion rates. These costs are generally about equal to the proceeds from equipment salvage upon abandonment of such properties. When estimated abandonment costs exceed the salvage value, the excess cost is accrued and expensed. Maintenance and repairs are charged to operating expenses.
Provision for depreciation and depletion of capitalized exploration and development costs are computed on the unit-of-production method based on proved developed reserves of oil and gas, as estimated by petroleum engineers, on a property by property basis. Prior to September 1, 1995, an additional valuation provision was made if total capitalized costs of oil and gas properties, excluding unproved properties, by country exceeded (1) the present value of future net revenues from estimated production of proved oil and gas reserves using constant prices discounted at 10% less (2) income tax effects related to differences between book and tax basis of the properties. Unproved properties are assessed periodically to determine whether they are impaired. When impairment occurs, a loss is recognized by providing a valuation allowance. When leases for unproved properties expire, any remaining cost is expensed. Depreciation of other assets are provided on the straight line method over their estimated useful lives.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Effective for the fourth quarter beginning September 1, 1995 the Company adopted Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). This statement prescribes the accounting for the impairment of long-lived assets, such as oil and gas properties. An impairment loss is reported as a component of income from continuing operations. The Company recognizes an impairment loss when the carrying value exceeds the expected undiscounted future net cash flows of each property pool at which time the property pool is written down to the fair value. Fair value is estimated to be a discounted present value of expected future net cash flows with appropriate risk consideration.
Adoption of this statement resulted in an impairment loss (non-cash charge) of $3,055,000 for the fourth quarter 1995 and was recognized as impairment expense to the oil and gas business segment. The Company reviewed the impairment of oil and gas properties for each successful efforts pool. Based on the new impairment policy, the B. R. Cox field in Texas and the Oklahoma, New Mexico and North Dakota property pools were determined to be impaired.
The Company uses crude oil and natural gas hedges to manage price exposure. Realized gains and losses on the hedges are recognized in oil and gas sales as settlement occurs.
The Company follows the entitlements method of accounting for gas balancing of gas production. The Company's gas imbalances are immaterial at November 30, 1996 and 1995.
Quasi-reorganization
In fiscal 1988, the Board of Directors adopted a corporate resolution which approved a quasi-reorganization effective December 1, 1987 and transferred $13,441,000 from additional paid-in capital to offset the accumulated deficit.
Other Property and Equipment
Gains and losses from retirement or replacement of other properties and equipment are included in income. Betterments and renewals are capitalized. Maintenance and repairs are charged to operating expenses.
Reclassification
The prior years expense categories for litigation and retirement and separation expenses have been reclassified to be consistent with the 1996 presentation.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Income Taxes
The Company files a consolidated income tax return with CGSI. Resources, its Canadian subsidiary, was also included in the consolidated U.S. income tax return through February 24, 1995 before terminating with completion of the divestiture. Resources was also subject to tax under applicable Canadian tax law. Columbus and its consolidated subsidiary have executed a tax allocation agreement which provides for an allocation and payment of U.S. income taxes based upon each Company's separate tax liability calculation.
Operating and Management Services
The Company recognizes revenue for operating and management services provided to other companies and non-operating interest owners in which the Company has no economic interest. The Company receives overhead fees, management fees and revenues related to gas marketing, compression and gathering.
The cost of providing such services is expensed and shown as "operating and management services" cost.
Earnings Per Share
Earnings per share are computed using the weighted average number of common shares outstanding. Stock options are included as common stock equivalents, when dilutive, using the treasury stock method. For 1996 common stock equivalents include shares issuable upon assumed exercise of dilutive stock options using the average price for primary shares and the much higher year end price for fully diluted shares. For 1995 and 1994 such common stock equivalents were not dilutive. Historical amounts have been adjusted for the 10% stock dividend distributions, in 1995 and 1994.
Accounting for Stock-Based Compensation
The Financial Accounting Standards Board issued Statement No. 123 on the "Accounting for Stock-Based Compensation". This statement prescribes the accounting and reporting standards for stock-based employee compensation plans and is effective for the Company's 1997 fiscal year. The Company has determined it will use the alternative pro forma disclosures as provided.
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, ---------------- 1996 1995 ---- ----
United United States States
Proved properties ............ $ 27,156 $ 22,153 Unproved properties .......... 875 91 -------- --------
28,031 22,244
Less accumulated depreciation, depletion, amortization and valuation allowance ........ (11,519) (9,414) -------- --------
Total net properties ......... $ 16,512 $ 12,830 ======== ========
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (in thousands)
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (in thousands)
(a) Production costs include lease operating expenses, production and property taxes (b) Amortization expense per equivalent barrel of production: 1996 - $3.86 1995 - $3.83 1994 - $2.78
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
For the years ended November 30, 1996, 1995 and 1994, 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.
1996 1995 1994 ------------------ ------------------ ------------------- Amount % Revenue Amount % Revenue Amount % Revenue
Customer A $3,142 29.7% $2,027 27.9% $ 1,755 13.4% Customer B 5,513 52.2 2,635 36.2 4,072 31.0 Customer C 1,212 11.5 1,046 14.4 1,423 10.8
In the Company's judgment, termination by any purchaser under which its present sales are made would not have a material impact upon its ability to sell its production to another purchaser at similar prices.
(4) INVESTMENT IN PARTNERSHIP
Columbus was formerly the managing general partner of Consolidated Energy Partners L.P. (the "partnership or "CPS"), and also operated almost all oil and gas properties owned by its subsidiary partnership, Consolidated Operating Partners L.P. ("COP"). When these partnerships were dissolved effective November 30, 1989, no partners received a cash distribution from their investment in CPS as the proceeds from the sale of the properties were less than the bank debt and other partnership liabilities.
Columbus, as managing general partner of COP, and Columbus as managing general partner had an obligation to pay for the respective partnership's costs incurred. Included in other current liabilities as of November 30, 1995 was $16,000 which represented remaining cash available to pay any valid claims that might become payable related to either liquidation or prior operations. During 1996, this amount was fully used to pay obligations of COP. During 1995, a settlement was reached with Jicarilla Apache Tribe relative to their claims for additional royalty owed for the period 1985 through 1992 from gas wells on their leaseholds in which COP owned varying interests and Columbus was operator. COP's share of the settlement was $95,000 which was paid during 1995 from the available cash on hand.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(5) LONG-TERM DEBT
The Company has a Credit Agreement ("Agreement") with Norwest Bank Denver, N.A. ("Bank") having a borrowing base which has been recently reduced at the request of Columbus to $7,000,000, which is subject to semi-annual redetermination for any increase or decrease. On October 23, 1996 the Credit Agreement was amended and restated to extend the revolving period and maturity date. The loan revolves until July 1, 1999 and then in its entirety converts to an amortizing term loan which matures July 1, 2003. The credit is collateralized by a first lien on oil and gas properties. The interest rate options are the Bank's prime rate or LIBOR plus 1 1/2%. In addition, a commitment fee of 1/4 of 1% of the average unused portion of the credit is payable quarterly.
At November 30, 1996 outstanding borrowings on the revolving line of credit were $2,200,000 and the unused borrowing base available was $4,800,000. The $2,200,000 bears interest at LIBOR rate of 5.44% plus 1 1/2%.
The Agreement as amended provides that certain financial covenants be met which include a minimum net worth of $8,300,000 plus 50% of Cumulative Net Income after November 30, 1991, a quarterly calculation of a current ratio of not less than 1.0:1.0 and a ratio of Funded Debt to Consolidated Net Worth not greater than 1.25:1.00. Columbus has complied with these covenants. Under the terms of the Agreement, Columbus is permitted to declare and pay a dividend in cash so long as no default has occurred or a mandatory prepayment of principal is pending.
The scheduled payments of long-term debt are as follows (in thousands):
Year ending November 30,:
1997 $ - 1998 - 1999 183 2000 550 2001 and after 1,467 -------
Total $ 2,200 =======
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(6) INCOME TAXES
The provision (benefit) for income taxes consists of the following (in thousands):
1996 1995 1994 ---- ---- ----
Current: Federal ................. $ 2 $ -- $ 57 Foreign (Canada) ........ -- 29 162 State ................... 79 20 72 ------- ------- ------- 81 49 291 ------- ------- -------
Deferred: Federal ................. 288 (612) 227 Use of loss carryforwards 848 -- 366 Foreign (Canada) ........ -- 44 253 State ................... 12 (8) 43 ------- ------- ------- 1,148 (576) 889 ------- ------- -------
Total income tax (benefit) expense ....... $ 1,229 $ (527) $ 1,180 ======= ======= =======
The components of earnings (loss) before income taxes are (in thousands):
1996 1995 1994 ---- ---- ----
U.S. $ 3,327 $(2,231) $ 2,167 Canada - 209 1,203 ------ ------- -------
Total $ 3,327 $(2,022) $ 3,370 ======= ======= =======
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 1996 1995 1994
U.S. Statutory rate 34 % (34)% 34% Foreign taxes (Canada) - 4 12 State income taxes 6 (4) 2 Change to post-1987 carryforwards 4 13 (7) Percentage depletion (7) (5) (4) Foreign tax credit/deduction - (4) (4) Other - 4 2 --- --- ---
Effective rate 37 % (26)% 35% === ==== ===
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company files a consolidated income tax return with its subsidiary and has executed a tax allocation agreement which provides for an allocation and payment of U.S. income taxes based upon each company's separate tax liability calculation.
The net operating loss carryforwards and percentage depletion deductions are for U.S. tax purposes only. For Canadian income tax purposes, when the annual taxable income of Resources exceeded its available Canadian tax allowances and deductions for that year, current income taxes were provided and a tax liability recorded. Canadian taxes were currently payable in 1995 and 1994. Consolidated U.S. income taxes are payable only when taxable income exceeds available U.S. net operating loss carryforwards and other credits.
Pursuant to provisions enacted as part of the Tax Reform Act of 1986, utilization of these corporate tax carryforwards in any one taxable year is limited if a corporation experiences a 50% change of ownership. Columbus experienced such a change of ownership in October, 1987 effectively limiting the utilization of pre-change ownership net operating losses to approximately $900,000 in each subsequent year. Subsequent additional ownership changes accumulated to more than 50% by August 25, 1993 thereby causing a second ownership change to occur. During 1996 Columbus utilized approximately $433,000 of remaining post-1987 net operating loss carryforwards which were limited and approximately $160,000 are available for fiscal 1997 and subsequent years.
Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109") requires the asset and liability approach be used to account for income taxes. Under this method, deferred tax liabilities and assets are determined based on the temporary differences between financial statement and tax basis of assets and liabilities using enacted rates in effect for the year in which the differences are expected to reverse. U.S. tax assets (net of a valuation allowance) primarily result from net operating loss carryforwards, percentage depletion and certain accrued but unpaid employee benefits. U.S. deferred tax liabilities result from the recognition of depreciation, depletion and amortization in different periods for financial reporting and tax purposes.
Because of the Company's previous 1987 quasi-organization, SFAS 109 requires the Company to report the effect of its net deferred tax asset arising prior to December 1, 1987 as an increase in stockholders' equity rather than as an increase to net earnings.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
During fiscal 1996, certain U.S. tax assets (shown in the table below) were utilized. Projected taxable income caused the Company to increase the valuation allowance during the year by $141,000.
The tax effect of significant temporary differences representing U.S. deferred tax assets and liabilities and changes were as follows (in thousands):
Current Year ------------------------------------ Dec. 1, Stockholders' Nov. 30, 1995 Equity Operations 1996 ------- ------- ---------- ------- Deferred tax assets: Pre-1987 loss carryforwards $ 1,976 $ -- $ (615) $ 1,361 Post-1987 loss carryforwards 720 -- (124) 596 Percentage depletion carryforwards ............ 894 -- 236 1,130 State income tax loss carryforwards ............ 197 -- (109) 88 Other ...................... 289 -- 19 308 ------- ------- ------- ------- Total ...... 4,076 -- (593) 3,483 Valuation allowance ..... (1,737) 409(a) (141) (1,469) ------- ------- ------- ------- Deferred tax assets . 2,339 409 (734) 2,014 ------- ------- ------- ------- Tax benefit of disqualifying disposition of incentive stock options ............ -- 102(a) (102) -- ------- ------- ------- -------
Deferred tax liabilities- Depreciation, depletion and amortization and other ... (1,701) -- (312) (2,013) ------- ------- ------- ------- Net tax asset ............ $ 638 $ 511 $(1,148) $ 1 ======= ======= ======= =======
(a) Credited to additional paid-in capital.
The Company has approximate net operating loss carryforwards (in thousands) available at November 30, 1996 as follows:
Net Expiration Year Operating loss
1999 $2,710 2000 907 2001 386 2003 45 2004 115 2010 1,593 ------- $ 5,756 =======
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
For U.S. Alternative Minimum Tax purposes the Company had net operating loss carryforwards of approximately $6,900,000 as of November 30, 1996. The Company also has percentage depletion carryforwards of $2,974,000 which do not expire. State income tax operating loss carryforwards of approximately $1,450,000 are available at November 30, 1996.
The earnings before income taxes for financial statements differed from taxable income as follows (in thousands):
1996 1995 1994 ---- ---- ----
Earnings loss) before income taxes per financial statements ....... $ 3,327 $(2,022) $ 3,370
Differences between income before taxes for financial statement purposes and taxable income: Intangible drilling costs deductible for taxes ......... (1,520) (3,125) (2,372) Excess of book over tax depletion, depreciation and amortization ............. 754 607 1,020 Disqualifying disposition of incentive stock options ...... (273) (88) (76) Impairment expense ............. 165 3,055 -- Lease abandonments ............. (117) (258) -- Dividend of rights of Resources -- 234 -- Other .......................... (95) 72 (105) ------- ------- ------- Federal taxable income ........... $ 2,241 $(1,525) $ 1,837 ======= ======= =======
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, 1996 as well as contemplated drilling activities, but excluding revenues from any possible future increase in proved reserves, management believes that taxable income during the carryforward period will be sufficient to partially utilize the NOL's before they expire. Of the total valuation allowance of $1,469,000 as of November 30, 1996, $998,000 relates to pre-quasi-reorganization tax assets and the balance of $471,000 relates to post-quasireorganization tax assets. In future periods, reduction of the pre-quasi-reorganization portion of the valuation allowance will be credited to additional paid-in capital and reduction of the postquasi-reorganization portion of the valuation allowance will be credited to income.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Estimates of future taxable income are subject to continuing review and change because oil and gas prices fluctuate, proved reserves are developed or new reserves added as a result of future drilling activities, and operation and management services revenue and expenses vary. A minimum level of $9,000,000 of future taxable income will be necessary to enable the Company to fully utilize the net operating loss carryforwards and realize the gross deferred tax assets of $3,483,000. This level of income can be achieved using the value of proved reserves reported in the year end November 30, 1996 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 1996 the valuation allowance was decreased by $409,000 related to pre-quasireorganization tax assets and increased by $141,000 for post-quasireorganization tax assets. During 1995 the valuation allowance was increased $96,000. During 1994 the valuation allowance was decreased by $182,000 related to pre-quasi-reorganization tax assets and decreased by $303,000 for post-quasi-reorganization assets.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(7) RELATED PARTY TRANSACTIONS
Columbus, as managing general partner, previously had certain responsibilities to CPS and COP. Additionally, Columbus is contingently liable for any debts and obligations of COP, excluding the non-recourse long-term debt to the bank, even though there has been a dissolution of CPS and COP. This would only occur after liquidation proceeds available have been exhausted. Columbus is not aware of any debts or obligations of COP that it may be liable for over those for which those proceeds have ben utilized.
Certain direct and indirect general and administrative costs incurred by CPS and COP were paid for by Columbus and reimbursed by CPS and COP. The following table sets forth reimbursements (included with operating and management services revenue) received for each period from COP.
G & A Allocated
Year Ended November 30, 1996 $ 5,000 Year Ended November 30, 1995 11,000 Year Ended November 30, 1994 22,000
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 $296,000 for fiscal 1996 and $213,000 for the nine months in 1995 following the divestiture of Resources.
(8) CAPITAL STOCK
Columbus has several stock option plans with outstanding options. Under the 1985 Plan, options for 73,431 shares were exercisable at November 30, 1996. No additional options may be granted under the 1985 Plan. At November 30, 1995, 87,360 shares were exercisable.
Under the 1995 Plan, as of November 30, 1996, 141,044 option shares remained available for granting, and options for 180,434 shares were exercisable. At November 30, 1995, 220,185 shares were available for granting, and options for 166,830 shares were exercisable.
The Board of Directors has granted nonqualified stock options of which there were 92,196 exercisable at November 30, 1996 and 5,296 shares were exercisable at November 30, 1995.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Options are granted at 100% of fair market value on date of grant. The following table represents a summary of stock option transactions for the three years ended November 30, 1996:
Shares Option Price
Balance, November 30, 1993 180,018 $ 3.72 to $ 8.42 Granted 202,829 8.26 to 8.47 Exercised (39,924) 4.13 to 7.70 Expired (5,897) 4.86 to 8.26 --------
Balance, November 30, 1994 337,026 3.72 to 8.47 Granted 181,965 6.44 to 7.94 Exercised (40,227) 3.72 to 5.89 Expired, exchanged or surrendered (196,745) 5.89 to 8.47 --------
Balance, November 30, 1995 282,019 4.34 to 8.47 Granted 245,800 5.25 to 10.63 Exercised (161,433) 4.34 to 8.30 Expired or exchanged (10,603) 6.44 to 8.30 --------
Balance, November 30, 1996 355,783 4.85 to 10.63 ========
As of August 1, 1995, the Board of Directors authorized an exchange of new stock option grants at the closing price ($6.625) on that date which equaled 80% of all previously granted stock options. These could be surrendered at the election of the holder provided that the holder previously had his monthly salary reduced as a part of the downsizing and administrative cost reduction program. Share options in the amount of 170,521 granted at prices from $5.87 to $8.47 were canceled and 66,015 share options were reissued as of August 1, 1995 and 70,400 non-statutory share options were reissued on February 5, 1996 at the fair market value of the Company shares on that date.
On October 28, 1992, the Board of Directors approved an Employee Stock Purchase Plan ("Plan") to begin January 1, 1993, which was approved by the shareholders at the 1993 annual meeting. Under the Plan a total of 220,000 shares were reserved from authorized unissued common stock from which payments by participants into the Plan will be utilized to purchase shares and the Company will contribute an amount of shares equivalent to 25% of those payments which will be issued out of the Company's treasury stock as vesting occurs semi-annually. For the fiscal 1996 and 1995 years a total of $13,000 and $17,000 matching contribution was accrued as an expense by the Company. The price of the issued shares equals the average trading price during each six month purchase period or the ending price, whichever is less. During fiscal 1996 a total of 12,394 shares were purchased (2,492 shares from treasury stock as the Company's contribution of 25%) at an average cost of $7.32 per share. During fiscal 1995 a total of 13,532 shares were purchased (2,719 shares from treasury stock for the Company contribution of 25%) at an average cost of $8.01 per share.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
During 1993 the Board of Directors authorized purchase from the market up to 350,000 shares of common stock (375,000 shares after stock dividend adjustment) to be held as treasury stock. A total of 249,200 shares were purchased during fiscal 1993 at an average cost of $9.18 per share. During fiscal 1994 an additional 80,500 shares were purchased at an average cost of $9.32 per share. This was followed by 45,300 shares purchased during first quarter 1995 at an average cost of $8.56 per share.
Another 300,000-share repurchase authorization was approved by the Board in February 1995, restricted to a maximum purchase price of $8.75 per share. A total of 197,900 shares were purchased during fiscal 1995 at an average cost of $7.29 per share. This was followed by 86,100 shares purchased during 1996 at an average cost of $6.73 per share.
(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.
Lease - In June 1991, Columbus executed a lease for office space for its present building which provides for monthly payments of $11,123, plus inflationary adjustments to an annual base operating expense, for a period of 60 months from October 1991 through October 1996. The total rent expense for 1996, 1995 and 1994 was approximately $133,000, $126,000 and $129,000 respectively. Columbus has renewed the lease for an additional two years through September 1998 at a base rate of $13,536 per month. Future rental payments, without regard to operating cost adjustments, required under this lease as of November 30, 1996 are $162,000 and $135,000 for fiscal years 1997 and 1998, respectively.
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.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 average year's average compensation. Such compensation has been approved for three individuals who have reached age 65. As of November 30, 1996 the accrued liability totals $178,000 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 $16,000 and $56,000 in 1996 and 1995, respectively.
During 1994, Columbus hedged natural gas prices by selling a "swap" of 100,000 Mmbtu per month for the twelve month period from May 1994 through April 1995 at an average daily price of $2.12 per Mmbtu. The swap was matched against the calendar monthly average price on the NYMEX and settled monthly resulting in an increase in revenues of $204,600 for the period from May through November 1994 and an increase in revenues of $283,900 during fiscal 1995 before its expiration in April 1995.
The Company subsequently entered into two new natural gas swaps by selling 60,000 Mmbtu per month for the period from April 1996 through November 1996 with one at $1.74 per Mmbtu and a second at $1.88 per Mmbtu. These volumes represented approximately 65% of Columbus' gas production at the time. To partially protect itself against possible escalating gas prices for October and November 1996, the Company purchased NYMEX futures contracts for those two months for 60,000 Mmbtu of natural gas at $1.805 and $1.875, respectively. The October call contract was sold for a profit of $37,500 in June 1996 and the November call option was sold for $4,500 in September 1996. These partially offset losses from the swaps for those months. For the eight month period, gas sales revenues were reduced by $560,000 as a result of the swaps because the market price at settlement exceeded the contract swap price.
Columbus also entered into a swap of crude oil prices by selling 10,000 barrels per month for the twelve month period from January 1996 through December 1996 at an average daily price of $17.25 per barrel with a cap of $19.50 as upside protection should crude oil futures soar for an unseen reason. This volume represented approximately 50% of its then current monthly production. The difference between the hedge price and the actual daily closing price on the NYMEX was settled monthly. Through November 1996 the swap reduced oil revenues by $232,000 with another $22,500 deducted for December 1996 because the market price at settlement exceeded $19.50 per barrel.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Columbus entered into another crude oil swap by selling a strip of 10,000 barrels per month for the twelve month period from November, 1996 through October, 1997 at an average daily price of $21.17 per barrel. This amount represents approximately 50% of Columbus' current crude oil production. A loss of $24,000 was incurred for the month of November 1996. Also, Columbus entered into a natural gas swap by selling 60,000 Mmbtu per month for the period from March 1997 through October 1997 at $2.20 per Mmbtu. This volume represents about 20% of Columbus' current natural gas production.
The Company's natural gas and crude oil swaps are considered financial instruments with off-balance sheet risk which were in the normal course of business to reduce its exposure to fluctuations in the price of crude oil and natural gas. Those instruments involve, to varying degrees, elements of market and credit risk in excess of the amount recognized in the balance sheets. The Company had natural gas and crude oil swaps outstanding subsequent to November 30, 1996 as follows:
Market or Settled Value as of Notional ---------------------- Value 11/30/96 2/7/97 ----- -------- ------
Natural gas (3/97-10/97) $ 1,056,000 $ 988,000 $ 1,110,000 Crude oil (12/96) 172,500 150,000 150,000 Crude oil (12/96-10/97) 2,328,700 2,286,000 2,248,000
The litigation expenses in 1995 and 1994 relate to two lawsuits. The first, Michael Mattalino, Bruce L. Davis and Maris E. Penn vs. Columbus Energy Corp. filed on April 23, 1993 was settled by agreement in September 1994. The second, Porter Farrell II vs. Columbus Energy Corp. filed October 14, 1993 had Columbus' motion for summary judgment granted on April 12, 1995 and the lawsuit was dismissed.
(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 $90,000, $101,000, and $77,000 in the fiscal years 1996, 1995 and 1994, respectively.
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:
(a) Approximately $294,000 of inter-segment revenues are included in service revenues in 1994, $105,000 in 1995 and are offset by the same amounts in oil and gas operating expenses.
(b) Other property and equipment have been allocated above to the oil and gas and services segment based upon the estimated proportion the property is used by each segment. Therefore, depletion, depreciation and amortization and identifiable assets do not match the functional allocations in Note 3 to the consolidated financial statements.
(c) Includes non-cash impairment loss of $165,000 in 1996 and $3,055,000 in 1995.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The Company conducted its foreign operations in Canada until February 1995 through its wholly-owned subsidiary, CEC Resources Ltd.
Summarized financial information concerning the foreign operations which is included in the preceding table is as follows:
1995 1994 (in thousands)
Operating revenues from unaffiliated services (a): Oil and gas $ 639 $ 2,436 Services 150 563 ------ ------- Total $ 789 $ 2,999 ====== =======
Depreciation, depletion and amortization: Oil and gas $ 116 $ 325 Services 17 63 ------ ------- Total $ 133 $ 388 ====== =======
Operating income: Oil and gas $ 225 $ 1,171 Services 106 497 General corporate expenses (121) (457) ------ ------- Total operating income 210 1,211
Interest expense and other 1 8 ------ -------
Earnings before income taxes $ 209 $ 1,203 ====== =======
Identifiable assets: Oil and gas $ - $ 4,680 Services - 675 ------ ------- Total $ - $ 5,355 ====== =======
Additions to property and equipment: Oil and gas $ 45 $ 1,499 Services 27 63 ------ ------- Total $ 72 $ 1,562 ====== =======
(a) Approximately $294,000 of inter-segment revenues are included in services revenues in 1994, $105,000 in 1995 and are offset by the same amounts in oil and gas operating expenses.
(12) 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, 1996 and 1995 the Company had investments in commercial paper of $1,000,000 and $1,200,000, respectively.
COLUMBUS ENERGY CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Columbus as operator of jointly owned oil and gas properties, sells oil and gas production to relatively large U.S. oil and gas purchasers (see Note 3), and pays vendors for oil and gas services. The risk of non-payment by the purchasers, counter parties to the crude oil and natural gas swap agreements or joint owners is considered minimal. The Company does not obtain collateral from its oil and gas purchasers for sales to them. Joint interest receivables are subject to collection under the terms of operating agreements which provide lien rights to the operator.
(13) ACQUISITION OF OIL AND GAS PROPERTIES (Unaudited)
In December 1995 Columbus purchased producing oil and gas properties in Texas which was recorded on December 1, 1995. Revenues and expenses for 1996 related to the acquisition have been included for the 12 months of the 1996 fiscal year. The pro forma results below are not necessarily indicative of what actually would have occurred if the acquisition had been in effect for the entire period presented. These results are not intended to be a projection of future results. The incremental effect of the acquired oil and gas properties summarized financial information (in thousands of dollars) for the 1995 fiscal year is as follows:
Revenues, net of operating expenses $1,152 Operating income(a) $ 469 Net income(b) $ 347 Earnings per share $ .11
(a) Net of pro forma depreciation and depletion and interest expense. (b) Net of pro forma income taxes at 26% effective rate.
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 21, 1997 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 By: /s/ Harry A. Trueblood, Jr. Executive Officer 2/21/97 - ------------------------------- ------- Harry A. Trueblood, Jr.
Chief Operating Officer
Executive Vice President By: /s/Clarence H. Brown and Chief Operating Officer 2/21/97 - ------------------------------- ------- Clarence H. Brown
Principal Accounting and Financial Officer
By: /s/Ronald H. Beck Vice President 2/21/97 - ------------------------------- ------- Ronald H. Beck
Majority of Board of Directors
By: /s/ Harry A. Trueblood, Jr. Director 2/21/97 - ------------------------------- ------- Harry A. Trueblood, Jr.
By: /s/Clarence H. Brown Director 2/21/97 - ------------------------------- ------- Clarence H. Brown
By: /s/J. Samuel Butler Director 2/21/97 - ------------------------------- ------- J. Samuel Butler
By: /s/William H. Blount, Jr. Director 2/21/97 - ------------------------------- ------- William H. Blount, Jr.
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, 1996
COLUMBUS ENERGY CORP. (Exact Name of Registrant)
1660 Lincoln Street Denver, Colorado 80264 (Address of Principal Executive Office)