ITEM 1. BUSINESS.
OVERVIEW
The Company is in the business of exploring for, producing and transporting oil and natural gas in Tennessee and Kansas. The Company leases producing and non-producing properties with a view toward exploration and development. Emphasis is also placed on pipeline and other infrastructure facilities to provide transportation, processing and tieback services. The Company utilizes state-of-the-art seismic technology to maximize the recovery of reserves. The Company's activities in the oil and gas business commenced in May 1995 with the acquisition of oil and gas leases in Tennessee.
Since 1995 the Company has acquired oil and gas leases on a total of approximately 60,000 acres, located in Hancock, Claiborne, Knox, Jefferson and Union Counties in Tennessee.
Effective December 31, 1997, the Company acquired from AFG Energy, Inc. ("AFG"), a private company, approximately 32,000 acres of leases in the vicinity of Hays, Kansas (the "Kansas Properties"). Included in the acquisition which closed on March 5, 1998 were 273 wells, including 208 working wells, of which 149 are producing oil wells and 59 are producing
gas wells, a related 50 mile pipeline and gathering system, 3 compressors and 11 vehicles. The total purchase price of these assets was approximately $5.5 million, which consisted of $3 million in cash and seller financing of $2.5 million. The seller financing portion of the purchase price was refinanced by Arvest United Bank of Oklahoma City, Oklahoma as evidenced by a note dated November 23, 1999 in the amount of $1,883,650 to be paid in monthly installments of principal and interest over a three year period. This obligation was subsequently satisfied from the proceeds of a line of credit received by the Company from Bank One, N.A. of Houston, Texas ("Bank One"). See, "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operation."
The Kansas Properties are currently producing approximately one million cubic feet of natural gas and 400 barrels of oil per day. Net revenues from the Kansas Properties at the present time is approximately $315,000 per month.
To date, the Company has been drilling primarily on a portion of its Tennessee leases, the 50,500 acre Swan Creek Field in Hancock County (the "Swan Creek Field or Leases") focused within the Knox formation, one of the geologic formations in the Field. It shortly intends to commence drilling in one of the other geologic formations in the Swan Creek Field. In 2001, the Company had 29 producing gas wells and 6 producing oil wells.
On November 18, 1999, the Company entered into a contract with Eastman Chemical Company ("Eastman"), in Kingsport, Tennessee, pursuant to which Eastman agreed to purchase a minimum of the lesser of 80% of its requirements or 10,000 MMBtu's (MMBTU MEANS ONE MILLION BRITISH THERMAL UNITS) of gas per day, for twenty years.
On March 30, 2001, the Company entered into a contract with BAE Systems ("BAE"), the operator of the Holston Army Ammunition Plant in Kingsport, Tennessee, pursuant to which BAE agreed to purchase all its gas requirements up to a maximum of 5,000 MMBtu's per day of gas for twenty years.
On March 8, 2001, the Company's wholly owned subsidiary, Tengasco Pipeline Corporation, completed a 65 mile intrastate pipeline from the Swan Creek Field to Kingsport, Tennessee at a cost to date of approximately $15.3 million through which it delivers its gas to Eastman, BAE and other customers in East Tennessee.
Delivery of gas to BAE commenced on April 4, 2001 and to Eastman on May 24, 2001. Commencing in June, 2001, the Company was producing approximately 5 million cubic feet of gas ("MMcf"are units of one million cubic feet of gas) per day from its existing wells in the Swan Creek Field. Based upon the estimated reserves contained in a reserve analysis report as of December 31, 2001 provided to the Company by Ryder Scott Company, L.P. and the initial production output of the existing wells, the Company anticipated that from existing wells and new wells to be completed during 2001, it would be able to produce and sell approximately 10 MMcf of gas per day to Eastman and BAE by the end of 2001. However, in view of the lack of production history from the wells or other wells in the area, various technical difficulties and
substantial problems with higher than expected fluids in the wells, led to significant reductions in the amount of gas produced and the Company was unable to meet these projected goals. At present, the Company is producing approximately 3MMcf of gas per day from its Swan Creek Field, a reduction from the average of 4-5 MMcf produced in the beginning of the second half of 2001. This reduction is the result of the problems discussed above; the fact that it was necessary to shut down many of the wells while work to resolve the problems was being done; and, the fact that the Company has temporarily stopped drilling any new wells in the Swan Creek Field due to the necessity of devoting its efforts to the task of improving the production from the existing wells.
At present, work has been completed on 11 wells to reduce the adverse effects of the fluid problems on the production of gas. Additional work to eliminate the fluid problems from the wells, and, in some cases, to drill new wells to replace troubled wells is ongoing, and the Company expects that production to increase substantially from the Swan Creek Field by the end of 2002. The Company's efforts will be aided significantly by geological information of the Knox formation derived from its experience with the wells already drilled. The Company has now been able to assimilate a detailed description and location of the primary producing geological structure. This now allows for enhanced placement and relocation of some wells into the more productive part of the Knox formation. This approach has been similar to a 3D seismic acquisition and evaluation without the high cost associated with such a procedure. As a result, although no assurances can be given, the Company believes that the amount of fluids in any of the new wells to be drilled in the Swan Creek Field will be significantly reduced. The Company hopes to commence drilling of new wells in the Swan Creek Field shortly. The Company will also continue to conduct exploration and production activities to produce increased quantities of crude oil and natural gas. See, "Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources" for discussion regarding funding for development activities.
HISTORY OF THE COMPANY
The Company was initially organized under the laws of the State of Utah on April 18, 1916, under the name "Gold Deposit Mining & Milling Company." The Company subsequently changed its name to Onasco Companies, Inc. The Company was formed for the purpose of mining, reducing and smelting mineral ores.
On November 10, 1972, the Company conveyed to an unaffiliated entity substantially all of the Company's assets and the Company ceased all business operations.
From approximately 1983 to 1991, the operations of the Company were limited to seeking out the acquisition of assets, property or businesses.
At a special meeting of stockholders held on April 28, 1995, the Company's stockholders voted:
(i) to approve the execution of an agreement (the "Purchase Agreement") pursuant to which the Company would acquire certain oil and gas leases, equipment, securities and vehicles owned by Industrial Resources Corporation ("IRC")(1), a Kentucky corporation, in consideration of the issuance of 4,000,000 post-split (as described below) "unregistered" and "restricted" shares of the Company's common stock and a $450,000 8% promissory note payable to IRC. The promissory note was converted into 83,799 shares of the Company's common stock in December 1995;
(ii) to amend the Articles of Incorporation of the Company to effect a reverse split of the Company's outstanding $0.001 par value common stock on a basis of one share for two, retaining the par value at $0.001 per share, with appropriate adjustments being made in the additional paid-in capital and stated capital accounts of the Company;
(iii) to change the name of the Company from "Onasco Companies, Inc." to "Tengasco, Inc."; and
(iv) to change the domicile of the Company from the State of Utah to the State of Tennessee by merging the Company into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose.
The Purchase Agreement was duly executed by the Company and IRC, effective May 2, 1995. The reverse split, name change and change of domicile became effective on May 4, 1995, the date on which duly executed Articles of Merger effecting these changes were filed with the Secretary of State of the State of Tennessee; a certified copy of the Articles of Merger from the State of Tennessee was filed with the Department of Commerce of the State of Utah on May 5, 1995. Unless otherwise noted, all subsequent computations herein retroactively reflect this one for two reverse split.
During 1996, the Company formed Tengasco Pipeline Corporation, a wholly-owned subsidiary, to manage the construction and operation of its pipeline, as well as other pipelines planned for the future.
GENERAL
1. THE SWAN CREEK FIELD
Amoco Production Company ("AMOCO") during the late 1970's and early 1980's, after extensive geological and seismic studies, acquired approximately 50,500 acres of oil and gas leases in the Eastern Overthrust in the Appalachian Basin, an area now referred to as the Swan
- ---------- (1) Malcolm E. Ratliff, the Company's Chief Executive Officer and Chairman of the Board of Directors, is the the sole shareholder of IRC.
Creek Field.
In 1982 AMOCO successfully drilled two significant natural gas discovery wells in the Swan Creek Field to the Knox Formation at approximately 5,000 feet of total depth. These wells, once completed, had a high pressure and volume of deliverability of natural gas; however, in the mid-1980's a substantial decline in worldwide oil and gas prices occurred and the high cost of constructing a necessary 23 mile pipeline across three rugged mountain ranges and crossing the environmentally protected Clinch River from Sneedville to the closest market in Rogersville, Tennessee was cost prohibitive.
In 1987, AMOCO farmed out its leases to Eastern American Energy Company which held the leases until July 1995. The Company became aware of a law adopted by the Tennessee legislature which enabled the Company to lease all of AMOCO's prior acreage. The Company filed for a declaratory judgment as to its right to lease AMOCO's prior acreage. The Company was ultimately successful in winning all right, title and interest in all of AMOCO's prior leases in a precedent setting Supreme Court case.
In July 1995 after completion of the Purchase Agreement with IRC, the Company acquired the Swan Creek Leases. These leases provide for a landowner royalty of 12.5%.
In July 1998 the Company completed the first phase ("Phase I") of its pipeline in the Swan Creek Field, a 30 mile pipeline made of 6 and 8 inch steel pipe running from the Swan Creek Field into the main city gate of Rogersville, Tennessee. With the assistance of the Tennessee Valley Authority ("TVA"), the Company was successful in utilizing TVA's right-of-way along its main power line grid from the Swan Creek Field to the Hawkins County Gas Utility District located in Rogersville. The cost of constructing Phase I of the pipeline was approximately $4,200,000.
Having completed Phase I of its pipeline, in July 1998 the Company began selling gas to Hawkins County Utility District which services residential, municipal and industrial customers in the Hawkins County area, pursuant to a written contract entered into on September 26, 1996. During the period from August 1998 through December 31, 1998 the Company delivered 46,776 cubic feet of gas to Hawkins County Utility District.
During the period from January 1, 1999 through March 23, 1999 Hawkins County Utility District took only 477 Mcf of gas ("Mcf" are units of one thousand cubic feet of gas) from the Company. Although Hawkins County Utility District could take gas in greater quantities, it declined to do so. Pursuant to its original contract, it was not obligated to purchase any specific amount of gas. The contract with the Hawkins County Utility District was renegotiated and an Amendment Agreement was entered into on October 19, 1999 whereby the Hawkins County Utility District committed to take a minimum of 500 Mcf and a maximum of 4,000 Mcf of gas per day with an option to purchase up to an additional 3,000 MCF per day. Pursuant to this Agreement, the Hawkins County Utility District began purchasing gas from the Company as of November 2, 1999. Hawkins County has purchased relatively small quantities of gas which the
Company was able to blend from certain wells to provide gas which contains less than 4% nitrogen. Hawkins County's position is that it is not required to purchase contract volumes unless the nitrogen content is less than 4%, although the Company has demonstrated that its gas, with a nitrogen content of approximately 4.5% is interchangeable with 4% gas. Since November 2, 1999, Hawkins County Utility District has purchased 3,910 Mcf of gas. The Company stands ready to deliver additional quantities of gas, but there can be no assurances that Hawkins County will purchase additional quantities of gas.
On November 18, 1999, the Company entered into an agreement with Eastman Chemical Company ("Eastman") which provides that the Company will deliver daily to Eastman's plant in Kingsport a minimum of the lesser of (i) 5,000 MMBtu's (MMBtu means one million British thermal units which is the equivalent of approximately one thousand cubic feet of gas) or (ii) forty percent (40%) of the natural gas requirements of Eastman's plant and a maximum of 15,000 MMBtu's per day. Under the terms of the agreement, the Company has the option to install facilities to treat the delivered gas so that the total non-hydrocarbon content of the delivered gas is not greater than two percent (2%). This will allow the gas to be used in certain processes in the Eastman plant requiring low levels of non-hydrocarbons. If the Company elects to perform this option by installing additional facilities, the minimum daily amount of gas to be purchased by Eastman from the Company will increase to the lesser of (i)10,000 MMBtu's or (ii) eighty percent (80%) of the natural gas requirements of Eastman's chemical plant.
On March 27, 2000, the Company and Eastman signed an amendment to the agreement permitting the Company a further option with respect to the allowable level of non-hydrocarbons in the delivered gas. This amendment gives the Company the further option to tender gas without treatment, at a minimum volume of 10,000 MMBtu's per day, in consideration of which the Company agrees to accept a price reduction of five cents per MMBtu for the volumes per day between 5,000 and 10,000 MMBtu's per day under the pricing structure in place under the original agreement. To date, none of the gas sold by the Company to Eastman exceeds the allowable level of non-hydrocarbons permitted under the agreement and does not require treatment.
Under the agreement as amended March 27, 2000, Eastman agreed to pay the Company the index price plus $0.10 for all natural gas quantities up to 5,000 MMBtu's delivered per day, the index price plus $0.05 for all quantities in excess of 5,000 MMBtu's per day and the index price for all quantities in excess of 15,000 MMBtu's per day. The index price means the price per MMBtu published in McGraw-Hill's INSIDE F.E.R.C Gas Market Report equal to the Henry Hub price index as shown in the table labeled Market Center Spot Gas Prices. During the six months ended February 28, 2002, the index price has ranged from a high of $3.19 per MMBtu in August 2001 to a low of $1.86 in October 2001.
The agreement with Eastman is for a term of twenty years and will be automatically extended, if the parties agree, for successive terms of one year. The initial term of the agreement was to commence upon the Company's completion of construction of Phase II of its pipeline and connection to Eastman's facilities and once commercial operation of that facility
was approved. Pursuant to its agreement with Eastman, completion of construction of Phase II of the pipeline was originally to be made by December 31, 2000. However, Eastman subsequently agreed to extend the completion date of construction to March 31, 2001.
Because the Company is required to enter into hedging agreements in fiscal 2002 pursuant to its credit facility agreement with Bank One, this may have an effect on the revenues it receives from actual sales of gas during that period. Under the credit facility agreement with Bank One, the volume made subject to the initial hedging agreement was not to be based on the Company's actual sales volumes. Under its present hedging agreement with Bank One which terminates on July 31, 2002, if the index price on a theoretical volume of 3,500 MMBtu per day of natural gas ranges between $2.50 and $3.01per MMBtu the Company's hedging will have no effect. However, if the index price falls below $2.50 per MMBtu the Company s hedging agreement will result in it actually receiving from Bank One under the hedge agreement, the difference between the actual price and $2.50 for the hedged volume of natural gas. If the index price rises above $3.01 per MMBtu the Company's hedging agreement will result in it actually paying to Bank One under the hedge agreement, the difference per MMBtu between the actual price and $3.01 for the hedged volume of natural gas.
On January 25, 2000, the Company's wholly owned subsidiary, Tengasco Pipeline Corporation ("Tengasco Pipeline"), signed a franchise agreement to install and operate new natural gas utility services to residential, commercial and industrial users in Hancock County, Tennessee for the Powell Valley Utility District. The Powell Valley District has no existing natural gas facilities and the system to be installed by Tengasco Pipeline will initially extend to schools and small customers, and will be gradually expanded over time to serve as many of the 6,900 residents of the County as is economically feasible. Tengasco Pipeline will purchase gas from the Company on behalf of the District and it will be resold at an average retail price of about $8.00 Mcf. Under the franchise agreement, which has an initial term of ten years and may be renewed for an additional ten years, Tengasco Pipeline will receive 95% of the gross proceeds of the sale of gas for its services under the agreement. In June, 2000, Tengasco Pipeline began installation of the necessary facilities to begin to serve up to 1,500 residential and industrial consumers in the City of Sneedville, county seat of Hancock County. The Company's existing eight inch main line from its Swan Creek Field passes through the city limits of Sneedville. A one-half mile of interconnecting pipeline from the Company's existing pipeline was installed, as well as an additional four miles of pipeline as the initial phase of the distribution system. The construction was completed and delivery of initial volumes of gas into the system from the Swan Creek field occurred on December 27, 2000. The cost of construction of these facilities was approximately $133,000. Upon enactment of initial rate schedules by the Powell Valley Utility District, initial sales began in January, 2001 to a small number of residential and small commercial customers. Tengasco Pipeline has contracted with the City of Sneedville to conduct billing and installation activities in connection with the day to day operation of this system. On March 11, 2002, the Company began delivering gas to its first commercial customer in a new industrial park in Sneedville, Kiefer Built, Inc, an Iowa based manufacturer of livestock and industrial trailers. The Company hopes to be able to supply gas to other customers who may move into that industrial park. At this time, no gas sales agreements for large volume or base load sales have been signed and there can be no assurances that such agreements will be signed and if
signed, it is not possible to predict when such sales may begin or what the overall volumes of gas sold may be.
On March 17, 2000, the Company announced that it had entered into an agreement with the University of Tennessee-Knoxville ("UTK") related to its hydrocarbon exploration activities in eastern Tennessee. Two UTK geological scientists, Professor Robert D. Hatcher, Jr., a University of Tennessee/Oak Ridge National Laboratory Distinguished Scientist in structural and Appalachian geology and now a Director of the Company, and Dr. Richard T. Williams, Ph. D., Associate Professor in geophysics, provide the Company with assistance in interpreting the structure of the Swan Creek Field and geophysical data from that field. New seismic data will permit better subsurface imaging and more exact determination of the size of the Swan Creek Field.
A major outgrowth of the Company's relationship with UTK is a new graduate fellowship, called the Tengasco Fellowship, to be awarded in UTK's Department of Geological Sciences to an outstanding graduate student interested in pursuing a career in the petroleum industry. The fellowship will provide a living allowance and tuition for the student. Two UTK PH. D. students receiving financial support from the Company have already provided computer generated 3-D images of the Swan Creek Field. These images have helped outline the subsurface shape of the hydrocarbon producing zone to allow the Company to better understand where additional production might be located.
The Company and the University of Tennessee have signed a Memorandum of Agreement concerning cooperation between them in the use of vibreosis seismic equipment, primarily a large vibrator truck, owned by the University that is to be used in the Company's exploration program. Under the agreement, the Company is entitled to use the equipment in exchange for performing required routine expert maintenance and upkeep on the University's equipment, the cost of which exceeds the University's available resources. The University-owned truck is identical to two trucks owned by the Company and used in its seismic exploration program.
In April 2000, Tengasco Pipeline commenced construction of Phase II of the Company's pipeline. When the pipeline was completed on March 8, 2001, an additional 35 miles of pipeline of 8 and 12 inch pipe had been laid at a cost to date of approximately $11.1 million extending the Company's pipeline from a point near the terminus of Phase I and connecting to an existing pipeline and meter station at Eastman's chemical plant. The completed pipeline extends 65 miles from the Company's Swan Creek Field to Kingsport, Tennessee.
On March 30, 2001, the Company signed a contract to supply natural gas to BAE SYSTEMS Ordnance Systems Inc. ("BAE"), operator of the Holston Army Ammunition Plant in Kingsport, Tennessee for a period of twenty years. Natural gas is used at the Holston Army ammunition facility to fire boilers and furnaces for steam production and process operations utilized in the manufacture of explosives by BAE for the United States military. Under the agreement, BAE's daily purchases of natural gas will be between 1.8 million and 5 million cubic
feet, and volume could increase significantly over the life of the agreement as BAE conducts additional operations at the Holston facility. The contract calls for a price based on the monthly published index price for spot sales of gas at the Henry Hub plus five cents per MMBtu in the same manner as the price is calculated in the contract between the Company and Eastman. The contract with BAE provides that the Company's obligation to sell gas to BAE is subject to availability of gas after the Company satisfies its obligation in accordance with Eastman's needs up to 15 MMcf per day.
The Company will be the sole supplier of natural gas to BAE under this agreement and the Company has the only gas pipeline located on the grounds of the 6,000-acre Holston facility. A portion of the Holston facility is being developed by BAE as the new Holston Business and Technology Park which will serve as a location for additional commercial and industrial customers. The Company's presence at the Holston Business and Technology Park will provide the availability of gas service to other customers and is considered by BAE to be an important factor in the development of the Park, as well as the source of potential new customers for the Company. Although the Company's gas production from its Swan Creek Field has not been sufficient to supply the quantity of gas that Eastman has been willing to purchase under its agreement with the Company, Eastman has not, to date, objected to sales of gas by the Company to BAE and others.
During 2001, the Company had 29 producing gas wells and six producing oil wells in the Swan Creek Field. Miller Petroleum, Inc. and others had a participating interest in twelve of these wells. See, "Item 2
ITEM 2. DESCRIPTION OF PROPERTY
PROPERTY LOCATION, FACILITIES, SIZE AND NATURE OF OWNERSHIP
The Company's Swan Creek Leases are on approximately 50,500 acres in Hancock, Claiborne, Knox, Jefferson and Union Counties in Tennessee. The initial terms of these leases vary from one to five years. Many of them can be extended at the option of the Company by payment of annual rent. Some of them will terminate unless the Company has commenced
drilling. However, the Company does not anticipate any difficulty in continuing the Swan Creek Leases.
Morita Properties, Inc., an affiliate of Shigemi Morita, a former Director of the Company, currently has a 25% working interest in nine of the Company's existing wells, and a 50% working interest and 6% working interest in two of the Company's other existing wells. All of these wells are located in the Swan Creek Field and are presently producing wells. In addition, to those interests, Morita Properties, Inc. previously owned a 25% working interest in three of the Company's other existing wells and 12.5% working interest in another of the Company's wells which it subsequently sold.
An individual who is not an affiliate of the Company purchased 25% working interests in two other wells, the Stephon Lawson No. 1 and the Patton No. 1. Both of these wells are located in the Swan Creek Field and are presently producing wells.
Another individual has a 29% revenue interest in the Laura Jean Lawson No. 3 well by virtue of having contributed her unleased acreage to the drilling unit and paying her proportionate share of the drilling costs of the well. The Company was obligated to allow that individual to participate on that basis in accordance with both customary industry practice and the requirements of the procedures of the Tennessee Oil and Gas Board in a forced pooling action brought by the Company to require the acreage to be included in the unit so that the well could be drilled. The forced pooling procedure was concluded by her contribution of acreage and agreement to pay proportionate share of drilling costs. This well is also located in the Swan Creek Field and is a presently producing well.
The Company also entered into a farmout agreement with Miller Petroleum, Inc. ("Miller") for ten wells to be drilled in the Swan Creek Field with the Company having an option to award up to an additional ten future wells. All locations were to be mutually agreed upon. Net revenues are to be 81.25% to Miller and the Company's subsidiary Tengasco Pipeline will transport Miller's gas. The Company reserved all offset locations to wells drilled under the farmout agreement. All ten wells have been drilled under the farmout agreement. The Company acquired back from Miller a 50% working interest from Miller in nine of those ten wells in addition to its rights under the farmout agreement. In addition, the Company and Miller have drilled two additional wells on a 50-50 basis, although the Company declined to exercise its option for a ten-well extension of the farmout agreement. Of the wells in which Miller owns an interest, six are presently producing.
Other than the working interests described or referred to in this Item, the Company retains all other working interests in wells drilled or to be drilled in the Swan Creek Field.
Working interest owners in oil and gas wells are entitled to market their respective shares of production to purchasers other than purchasers with whom the Company has contracted. Absent such contractual arrangements being made by the working interest owners, the Company is authorized but is not required to provide a market for oil or gas attributable to working interest
owners' production. At this time, the Company has not agreed to market gas for any working interest owner to customers other than customers of the Company. If the Company does agree to market gas for working interest owners to the Company's customers, the Company will have to agree, at that time, to the terms of such marketing arrangements and it is possible that as a result of such arrangements, the Company's revenues from such customers may be correspondingly reduced. If the working interest owners make their own arrangements to market their natural gas to other end users along the pipeline which have been served by East Tennessee Natural Gas, an interstate pipeline, such gas would be transported through the Company's wholly owned subsidiary Tengasco Pipeline at published tariff rates. The current published tariff rate is for firm transportation at a demand charge of five cents per MMBtu per day plus a commodity charge of $0.80 per MMBtu. If the working interest owners do not market their production, either independently or through the Company, then their interest will be treated as not yet produced and will be balanced either when marketing arrangements are made by such working interest owners or when the well ceases to produce in accordance with customary industry practice.
The Kansas Properties contain 138 leases totaling 32,158 acres in the vicinity of Hays, Kansas. The original term on these leases was from 1 to 10 years and in most cases has expired, however, most leases are still in effect because they are being held by production. The Company maintains a 100% working interest in most wells. The leases provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%.
The Company pays ad valorem taxes on its Kansas Properties. It does not pay any taxes on its Swan Creek Leases. The Company has general liability insurance for the Kansas Properties and the Swan Creek Field.
The Company leases its principal executive offices, consisting of approximately 5,647 square feet located at 603 Main Avenue, Suite 500, Knoxville, Tennessee, at a monthly rent of $4,705.83. The Company also leases a field office in Sneedville, Tennessee at a rental of $500 per month, an office in Hays, Kansas at a rental of $500 per month and an office in New York City at a rental of $2,600 per month.
RESERVE ANALYSES
Ryder Scott Company, L.P. of Houston, Texas ("Ryder Scott") has performed reserve analyses of all the Company's productive leases. Ryder Scott and its employees and its registered petroleum engineers have no interest in the Company or IRC, and performed these services at their standard rates. The net reserve values used hereafter were obtained from a reserve report dated March 28, 2002 (the "Report") prepared by Ryder Scott as of December 31, 2001. In substance, the Report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical judgment. Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies, commercial services, outside operators and files of Ryder Scott. The net reserve values
in the Report were adjusted to take into account the working interests that have been sold by the Company in various wells in the Swan Creek Field. The Report provides that the net proved reserves for wells in the Swan Creek Field is 23,006 MMcf of natural gas and 224,745 barrels of oil. According to the Report, the value of the future gross revenues of the Company's interest in the Swan Creek Field as of December 31, 2001 is $57,832,005 before production taxes and $56,097,044 after production taxes. The Report further provides that as of December 31, 2001 the value of the future net income before income taxes of the Company's interest in the Swan Creek Field is $41,478,067 and discounting the future net income by 10% results in a present value of $19,302,590.
The Report reflects a reduction in the amount of proved natural gas reserves from 33,576.581 MMcf to 23,006.332 MMcf and proved oil reserves from 284,673 barrels to 224,745 barrels in the Swan Creek Field from the reserves as provided in the Ryder Scott report dated August 10, 2001 reporting values as of June 30, 2001. This reduction is a result of the later Report placing greater emphasis on the initial production figures from the Swan Creek Field during the period from June to December 2001 which were adversely affected by initial production problems as described above in "Item 1 Business - General - 1. Swan Creek". The earlier Ryder Scott report as of June 30, 2001, on the other hand, was based primarily on volumetric calculations rather than actual production figures because production from the Swan Creek had just begun. The Company anticipates that the reserve report will not only stabilize at no less than current levels of production but increase in future reporting periods when it is expected that production will increase as a result of ongoing work on existing wells and the drilling of new wells. The Report also reflects a reduction of 48.8% in the net present value of the oil and gas reserves in the Swan Creek Field from the values reported in the Ryder Scott reserve report dated June 30, 2001. This reduction occurred not only as a result of the amount of reserves reported, but in addition, as a result of the much lower oil and gas prices being received at year end as stated in the Report which were approximately $7.75 per barrel of oil and $.80 Mcf of gas lower than the prices which served as the basis for Ryder Scott's earlier June 30, 2001 report.
The Report reflects a substantial reduction in the amount of proved natural gas reserves from 44,451.338 MMcf to 23,006.332 MMcf and proved oil reserves from 376,296 barrels to 224,745 barrels in the Swan Creek Field from the reserves in an earlier Ryder Scott reported dated March 28, 2001 reporting values as of December 31, 2000.This results from the fact that the earlier report was based entirely on volumetric calculations because production had not yet commenced. In addition, the Report reflects a significant reduction of the discounted (at 10% per annum compounded monthly) net present value of the Company's oil and gas reserves in the Swan Creek field from $300,208,036 to $19,302,590. Although this reduction is based in part on the reduction in reserves for the reasons stated, a most significant factor in this reported reduction of net present value is the use of much lower price projections in the valuation of the reserves. The year-end 2000 report utilized near-record gas prices of $9.77 per Mcf and oil prices of $24.10 per barrel as opposed to the $2.13 per Mcf price and $17.24 per barrel price utilized in the current Report for the year ending December 31, 2001. This represents a 78% reduction in gas prices, and a 28% reduction in oil prices. Finally, the reduction in net present value as stated in the Report also occurred in part because the projected life of the Swan Creek
reserves for the year ending December 31, 2001 is more than doubled (from 26.14 years to 57.67 years) from the report for the year ending December 31, 2000. This has the arithmetical result of amplifying the effect of the ten percent (compounded monthly) discount factor used in determining a net present value of the total future income stream, because the discount factor is applied and compounding occurs over the longer period of time (56.7 years as opposed to 26.14 years) during which production is projected to occur.
Ryder Scott also performed a reserve analysis of the Kansas Properties. The Report provides that the net proved reserves for wells in the Swan Creek Field is 2,873 MMcf of natural gas and 831,930 barrels of oil. According to the Report, the value of the future gross revenues of the Company's interest in the Kansas Properties as of December 31, 2001 is $20,463,797 before production taxes and $19,586,607 after production taxes. The Report further provides that as of December 31, 2001 the value of the future net income before income taxes of the Company's interest in the Kansas Properties is $4,350,410 and discounting the future net income by 10% results in a present value of $2,431,317.
The Report reflects a reduction from the earlier Ryder Scott report as of December 31, 2000 in (i) the number of barrels of oil attributed to the Company's net interest in the Kansas Properties from 1,438,209 barrels to 831,930 barrels and (ii) the value of the future gross revenues of the Company's interest in the Kansas Properties from $54,419,609 before production taxes and $54,307,992 after production taxes as of December 31, 2000 to $20,463,797 before production taxes and $19,586,607 after production taxes as of December 31, 2001. These reductions are due primarily to two factors. First, the reduction in the number of barrels occurred because the Report disregarded the reserves attributable to approximately thirty wells that are still actually producing oil, because the calculated operating expenses for those wells matched or exceeded the theoretical crude oil price being utilized in the Report. Because the current market price of crude oil has risen from the price used in the Report, all or a portion of the reserves attributable to these wells would now be included in an analysis of the Company's reserves, depending upon the level of price received for crude oil and the relationship of such price to operating expenses. Second, the Report in determining the value of future gross revenues from the Kansas Properties used lower prices than utilized in the report ending December 31, 2000. The Report used a gas price of $2.13 in contrast to the $5.30 price used in 2000, and an oil price of $17.21 in contrast to the $26.46 price used in 2000. The combination of these factors also resulted in a decrease in the net present value of the Company's future income from the Kansas Properties calculated at a discount of 10%, from $14,993,222 as of December 31, 2000 to $2,431,317 as of December 31, 2001. The Company anticipates that future reports of the net present value of the Kansas Properties will rise with any increase in market pricing and the resulting consideration of reserves attributable to all of the Company's wells, which are still producing in accordance with their extended production history.
The Company believes that the reserve analysis reports prepared by Ryder Scott for the Company for the Swan Creek Field and Kansas Properties provide an essential basis for review and consideration of the Company's producing properties by all potential industry partners and all financial institutions across the country. It is standard in the industry for reserve analyses such as these to be used as a basis for financing of drilling costs. Reserve analyses, however, are
at best speculative, especially when based upon limited production; no assurance can be given that the reserves attributed to these leases exist or will be economically recoverable. The result of any reserve analysis is dependent upon the forecast of product prices utilized in the analysis which may be more or less than the actual price received during the period in which production occurs.
The Company has not filed the reserve analysis reports prepared by Ryder Scott or any other reserve reports with any Federal authority or agency other than the Securities and Exchange Commission.
PRODUCTION
The following tables summarize for the past three fiscal years the volumes of oil and gas produced to the Company's interests, the Company's operating costs and the Company's average sales prices for its oil and gas. The information does not include volumes produced to royalty interests or other working interests.
- -------------------------------------------------------------------------------- TENNESSEE - -------------------------------------------------------------------------------- YEAR ENDED PRODUCTION COST OF PRODUCTION AVERAGE SALES PRICE DECEMBER 31 (PER BOE)(2) - -------------------------------------------------------------------------------- OIL GAS OIL GAS (Bbl) (Mcf) (Bbl) (PER Mcf) - -------------------------------------------------------------------------------- 2001 22,776.21 703,073.56 $0.31 $16.05 $2.55 - -------------------------------------------------------------------------------- 2000 37,210.67 2,411.00 $0.69 $20.32 $2.86 - -------------------------------------------------------------------------------- 1999 17,286.06 2,122.00 $0.44(est.) $12.81 $2.86(est.) - --------------------------------------------------------------------------------
Gas volumes and prices for 1999 and 2000 reflect only the nominal purchases made by Hawkins County Gas Utility District upon completion of Phase I of Tengasco Pipeline Company's pipeline system. See Item I, "Business-General-1 Swan Creek Field."
- ---------- (2) A "BOE" is a barrel of oil equivalent. A barrel of oil contains approximately 6 Mcf of natural gas by heating content. The volumes of gas produced have been converted into "barrels of oil equivalent" for the purposes of calculating costs of production.
- -------------------------------------------------------------------------------- KANSAS - -------------------------------------------------------------------------------- YEAR ENDED PRODUCTION COST OF PRODUCTION AVERAGE SALES PRICE DECEMBER 31 (PER BOE) - -------------------------------------------------------------------------------- OIL GAS OIL GAS (Bbl) (Mcf) (Bbl) (PER Mcf) - -------------------------------------------------------------------------------- 2001 112,495.88 278,884.66 $10.72 $23.50 $4.12 - -------------------------------------------------------------------------------- 2000 111,734.81 291,096.22 $ 9.68 $28.06 $3.75 - -------------------------------------------------------------------------------- 1999 114,732.28 304,059.81 $ 8.87 $17.23 $2.16 - --------------------------------------------------------------------------------
OIL AND GAS DRILLING ACTIVITIES
The Company's oil and gas developmental drilling for the past three fiscal years are as set forth in the following tables. During the fiscal years ending December 31, 1999, 2000 and 2001, the Company did not drill any exploratory wells. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of wells drilled, quantities of reserves found or economic value.
GROSS AND NET WELLS
The following tables set forth for the fiscal years ending December 31, 1999, 2000 and 2001 the number of gross and net development wells drilled by the Company. The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interests the Company owns in gross wells.
- -------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31 - -------------------------------------------------------------------------------- 2001 2000 1999 - -------------------------------------------------------------------------------- GROSS NET GROSS NET GROSS NET - -------------------------------------------------------------------------------- TENNESSEE - -------------------------------------------------------------------------------- PRODUCTIVE WELLS 19 11.42 9 4.0515 7 4.8125 - -------------------------------------------------------------------------------- DRY HOLES 0 0 0 0 0 0 - -------------------------------------------------------------------------------- KANSAS - -------------------------------------------------------------------------------- PRODUCTIVE WELLS 3 2.594 0 0 0 0 - -------------------------------------------------------------------------------- DRY HOLES 0 0 0 0 0 0 - --------------------------------------------------------------------------------
PRODUCTIVE WELLS
The following table sets information regarding the number of productive wells in which the Company held a working interest as of December 31, 2001. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. One or more completions in the same bore hole are counted as one well.
- -------------------------------------------------------------------------------- GAS OIL - -------------------------------------------------------------------------------- GROSS NET GROSS NET - -------------------------------------------------------------------------------- TENNESSEE 34 20.7475 11 5.308 - -------------------------------------------------------------------------------- KANSAS 52 43.4504 134 112.8382 - --------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED OIL AND GAS ACREAGE
As of December 31, 2001, the Company owned working interests in the following developed and undeveloped oil and gas acreage. Net acres refers to the Company's interest less the interest of royalty and other working interest owners.
- -------------------------------------------------------------------------------- DEVELOPED UNDEVELOPED - -------------------------------------------------------------------------------- GROSS ACRES NET ACRES GROSS ACRES NET ACRES - -------------------------------------------------------------------------------- TENNESSEE 1,840.00 1,065.38 62,651.90 54,820.00 - -------------------------------------------------------------------------------- KANSAS 9,666.00 8,080.44 22,711.00 18,995.48 - --------------------------------------------------------------------------------
ITEM 3.
ITEM 3. - LEGAL PROCEEDINGS
Except as described hereafter, the Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state or local governmental agency is presently contemplating any proceeding against the Company which would have a
result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company's common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.
1. The Company, its Chief Executive Officer, Malcolm E. Ratliff, and one of its attorneys, Morton S. Robson, have been named as defendants in an action commenced in the Supreme Court of the State of New York, New York County entitled MAUREEN COLEMAN, JOHN O. KOHLER, CHARLES MASSOUD, JONATHAN SARLIN, VON GRAFFENRIED A.G. AND VPM VERWATUNGS A.G., PLAINTIFFS V. TENGASCO, INC., MORTON S. ROBSON AND MALCOLM E. RATLIFF, DEFENDANTS, INDEX NO. 603009/98. In that action, the plaintiffs, shareholders of the Company each of which purchased restricted shares of the Company's Common Stock, allege that although they were entitled to sell their shares pursuant to SEC Rule 144 in the open market, they were precluded from doing so by the defendants' purported wrongful refusal to remove the restrictive legend from their shares. The plaintiffs own in the aggregate 35,000 shares of the Company's common stock. The plaintiffs are seeking damages in an amount equal to the difference between the amount for which they would have been able to sell their shares if the defendants had acted to remove the restrictive legends when requested and the amount they will receive on the sale of their shares. The plaintiffs are also seeking punitive damages in an amount they claim to be in excess of $500,000 together with interest, costs and disbursements of bringing the action, including reasonable attorneys fees. This action has been partially settled by the Company agreeing to remove the restrictive legends on the plaintiffs' stock.
As for the balance of the action, the Company believes that there are several substantial factual and legal issues as to the date on which the shareholders were entitled to sell their stock pursuant to Rule 144. Management further believes that the Company did not wrongfully withhold its approval of the removal of the restrictive legends at the times such removal was requested by the shareholders. However, in the event the Company is found to have improperly withheld its permission to remove the restrictive legends from the shares owned by the shareholders, the Company may be held liable for damages to the shareholders in an amount equal to the difference between the actual sale price of such shares and the sales price they would have realized on the date such restrictive legends should have been permitted to be removed. At this time it is not possible to ascertain with any certainty what such damages would be. The plaintiffs have not taken any action in this matter for several years.
2. TENGASCO PIPELINE CORPORATION V. JAMES E. LARKIN AND KATHLEEN A. O `CONNOR, No. 4929J in the Circuit Court for Hawkins County, Tennessee. This is a condemnation proceeding brought by Tengasco Pipeline Corporation to acquire a temporary construction easement and permanent right of way to maintain and operate a portion of Phase I of the Company's pipeline in Hawkins County, Tennessee. The court granted an order of possession to the Company in January, 1998 and the pipeline has been constructed across approximately 3,000 feet of the property concerned in a rural and very steep locale. The Company has had the right of way appraised at $4,000. The landowners, Mr. Larkin and Kathleen A. O Connor who both live on the property, contest the appraised value of the property and claim incidental damages to
certain fish ponds located on their property. The landowners, despite a lack of evidence of any fish raising or aquaculture business actually being or having been operated on the premises or of any actual losses to such business, have counterclaimed for $867,585 in compensatory damages and $2.6 million in punitive damages arising from trespass and other legal theories. The Court required the parties to attempt to mediate this dispute and the mediation occurred in December, 2000. The parties were unable to reach a mediated settlement and the matter has been scheduled for trial on May 8, 2002. The discovery conducted to date has not disclosed any facts that reasonably suggest any likelihood of a substantial adverse result in this matter, and the Company intends to vigorously defend the allegations of the counterclaim which appear to be without any credible basis.
3. The Company and its wholly owned subsidiary, Tengasco Pipeline Corporation ("TPC"), were named as defendants in an action commenced on June 4, 2001 by C.H. Fenstermaker & Associates, Inc. ("Fenstermaker") in the United States District for the Eastern District of Tennessee entitled C.H. FENSTERMAKER & ASSOCIATES, INC. V. TENGASCO, INC., No. 3:01-CV-283.
The action seeks to recover approximately $365,000 in fees and charges billed to TPC for engineering services Fenstermaker claims it performed in connection with the planning and construction of Phase II of the Company's pipeline which runs from Rogersville, TN to Kingsport, TN to serve Eastman Chemical Company and Holston Army Ammunition Plant.
On June 25, 2001, the Company and TPC filed an answer to the complaint denying liability for the billings claimed, and counterclaiming against Caddum, Inc. ("Caddum"), an unincorporated division of Fenstermaker. The counterclaim seeks recovery from Caddum of damages for breach of contract and breach of professional engineering standards caused by the actions of Caddum, including unauthorized deviations from the pipeline route which caused the Company to incur significant additional costs. These costs included substantial fees for concrete capping of the pipeline as a result of the pipeline being placed to close to the adjoining highway right of way. The counterclaim further alleges that Caddum damaged the Company by: causing delays in completing the pipeline; by failing to submit engineering drawings and failing to timely obtain certain x-rays of the pipeline welds; its unauthorized actions in ordering supplies and materials; and, overbilling from the agreed contract rate for engineering services. The counterclaim seeks actual damages from Caddum of approximately $475,000, treble damages under state law for the overbilling, and damages to the Company arising from the delay caused by Caddum in the production from the Swan Creek field all in the aggregate amount of $1.25 million. The District Court has scheduled the case for a non-jury trial on July 17, 2002 before Judge James H. Jarvis. The Company believes its counterclaims are meritorious and intends to vigorously prosecute them and anticipates that, at a minimum, its counterclaims will either fully offset or substantially reduce exposure to liability for the amounts claimed by Fenstermaker.
4. On October 10, 2001 an arbitration hearing was held by the American Arbitration Association between the Company's wholly owned subsidiary Tengasco Pipeline Corporation ("TPC") and King Pipeline & Utility Company ("King"), the contractor for the
construction of Phase II of the Company's pipeline. The arbitration was held to resolve disputes concerning final billings by King for the pipeline construction. King made four claims, seeking (1) payment for straw matting done by King on slopes calculated at two dollars per square foot; (2) to retain payment it had received for clearing and grubbing charges; (3) the release of a currently retained sum of $46,585, to which TPC made no claim, presently being held in escrow pending the outcome of ongoing litigation between King and King's boring subcontractor; and (4) payment of $94,000 billed by King for alleged extra work it performed in trenching at a depth deeper than called for by the contract.
On October 31, 2001 the arbitrator issued his award finding that King was entitled to recover the sum of $266,390.66 for straw matting work performed by King, calculated at $2 per square foot as sought by King; that King was entitled to retain the $72,500 payment made to it by TPC for clearing and grubbing work, and that the retained sum be released from escrow. The arbitrator denied all relief sought by King for extra charges in the amount of $94,000 for deeper trenching, and awarded King its attorneys fees of approximately $14,000. TPC has filed a motion to vacate the arbitrator's award and King has filed an opposing motion to confirm the award. The motions are expected to be heard shortly in the Chancery Court for Knox County, Tennessee. In the event TPC's motion is denied and King's opposing motion is granted, the Company is examining the possibility of appealing the award, since the Company believes that the arbitrator's ruling is not supported by the record presented. However, available grounds for appeal appear extremely limited and it is therefore unlikely that an appeal will occur. In the event an appeal is unavailable and payment is made to satisfy the award, then based on the evidence presented at the arbitration hearing, the Company and TPC intend to seek recovery of the payments made to King as an additional element of damages being sought from Caddum, Inc., the project engineer, in the action now pending in the United States District Court for the Eastern District of Tennessee entitled C.H. FENSTERMAKER & ASSOCIATES, INC. V. TENGASCO, INC., No. 3:01-CV-2 discussed above.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None during the fourth quarter of 2001.
PART II
ITEM 5
ITEM 5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
The Company's common stock was listed on the OTC Bulletin Board of the NASD from March 31, 1994 through December 20, 1999 under the symbol TNGO. On December 10, 1999, the American Stock Exchange ("AMEX") approved the application of the Company to have its common stock listed on the AMEX. Trading of the Company's common stock on the AMEX commenced on December 21, 1999 under the symbol TGC.
The range of high and low closing prices for shares of common stock of the Company during the fiscal years ended December 31, 2000 and December 31, 2001 are set forth below. The prices have been retroactively adjusted by a 5% reduction to take into account the 5% stock dividend declared by the Company payable on October 1, 2001 to all shareholders of record as of September 4, 2001.
HIGH LOW ---- --- For the Quarters Ending
March 31, 2001 14.20 9.69
June 30, 2001 15.01 11.16
September 30, 2001 13.69 7.60
December 31, 2001 10.54 7.39
March 31, 2000 9.86 6.65
June 30, 2000 9.26 6.65
September 30, 2000 9.26 7.60
December 31, 2000 12.82 7.84
HOLDERS
As of March 1, 2002 the number of shareholders of record of the Company's common stock was 375 and management believes that there are approximately 2,172 beneficial owners of the Company's common stock.
DIVIDENDS
The Company under its credit agreement with Bank One is presently restricted from paying dividends without Bank One's consent. On July 30, 2001, the Company's Board of Directors voted to declare a five percent (5%) stock dividend on the outstanding shares of the Company's common stock, $.001 par value which was payable on October 1, 2001 to all shareholders of record as of September 4, 2001. No fractional shares were issued in connection with the stock dividend and all such fractional shares were rounded to the next full share. The Company has no present plans to declare any further dividends with respect to its common stock.
RECENT SALES OF UNREGISTERED SECURITIES
Except as previously reported in Quarterly Reports on Form 10-QSB and Form 10-Q filed by the Company, the following tables sets forth certain information as to all equity securities, other than the grant of options, which were sold during the past year, including the sale of common stock upon the exercise of outstanding options and warrants, that were not registered under the Securities Act of 1933, as amended,
COMMON STOCK DATE NUMBER OF AGGREGATE NAME OF OWNER ACQUIRED SHARES CONSIDERATION - ------------- -------- ------ ------------- Kenny Securities 7/13/01 12,000 $ 82,500 Kenny Securities 7/13/01 17,285 $ 109,328 Bill L. Harbert 8/9/01 111,111 $1,000,000.00 Jerome & Lynn Cipponeri 12/31/01 16,000 $ 100,000.00
In addition to the foregoing, on December 20, 2001, the Company issued 5,000 shares of its common stock to a non-affiliated individual in payment of $70,000 for services he had performed for the Company.
Management believes that all of the foregoing persons were either "accredited investors" as that term is defined under applicable federal and state securities laws, rules and regulations, or were persons who by virtue of background, education and experience who could accurately evaluate the risks and merits attendant to an investment in the securities of the Company. Further, all such persons were provided with access to all material information regarding the Company, prior to the offer or sale of these securities, and each had an opportunity to ask of and receive answers from directors, executive officers, attorneys and accountants for the Company. The offers and sales of the foregoing securities are believed to have been exempt from the registration requirements of Section 5 of the 1933 Act, as amended, pursuant to Section 4(2) thereof, and from similar state securities laws, rules and regulations covering the offer and sale of securities by available state exemptions from such registration.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data have been derived from the Company's financial statements, and should be read in conjunction with those financial statements, including the related footnotes.
Years Ended December 31,
- ---------- (3) All references in this table to common stock and per share data have been retroactively adjusted to reflect the 5% stock dividend declared by the Company effective as of September 4, 2001.
As of December 31,
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
RESULTS OF OPERATIONS
The Company incurred a net loss to holders of common stock of $2,653,970 ($0.26 per share) in 2001 compared to a net loss of $1,799,441 ($0.19 per share) in 2000 and $2,791,270 ($0.33 per share) in 1999.
The Company realized oil and gas revenues of $6,656,758 in 2001 as compared to $5,241,076 in 2000 and $3,017,252 in 1999. The increase from 2000 to 2001 was primarily due to gas sales from the Swan Creek Field of $2,563,935. However, Kansas oil sales decreased $489,778 from 2001 to 2000 due to price decreases as the number of barrels produced remained constant. The Kansas Properties produced 113,758 barrels in 1999, 143,949 barrels in 2000, and 143,291 barrels in 2001. Also oil production decreases and price decreases in Swan Creek reduced oil revenues from $960,814 in 2000 to $499,641 in 2001. This was due to the combination of price and volume. Volumes decreased from 47,281 barrels in 2000 to 30,323 barrels in 2001. This was due to the Company's concentration on drilling new gas wells. The Company's subsidiary, Tengasco Pipeline, did have pipeline transportation revenues for the first
- ---------- (4) During the years ended December 31, 2000, 1999, 1998 and 1997, this included portions which were under construction.
(5) No cash dividends have been declared or paid by the Company for the periods presented.
time in 2001 of $296,331 from the Swan Creek Field.
The Company's realized oil and gas revenues increased $2,223,824 in 2000 as compared to 1999. The increase in revenues was primarily attributable to the increase in oil and gas prices in 2000. However, the Kansas properties oil production increased in 2000 by 30,191 barrels and the Swan Creek oil production increased by 25,317 barrels in 2000.
The Company's production costs and taxes have increased each year from 1999 to 2001 as additional cost has been incurred to maintain the Kansas wells and also to begin production from the Swan Creek Field for the first time in 2001. The 2001 increase of $337,332 as compared to 2000 is due primarily to the commencement of production from the Swan Creek Field. Production costs and taxes only increased $49,482 from 1999 to 2000.
Depletion, depreciation, and amortization increased significantly in 2001 over 2000 and 1999 levels. The primary increase is due to significant increases in depletion expense during 2001 ($1,142,000) as a result of the following: decreases in reserve estimates on oil and gas properties arising from declining commodity prices; certain of the Company's gas wells had decreased production levels at year-end due to problems encountered with liquids in the wells. This decreased production level at year-end was factored into the estimated future proved reserves calculation performed as of December 31, 2001, resulting in a lower future proved reserves estimate. Additionally, the Company took depreciation on the pipeline for the first time in 2001 ($220,371). The depletion, depreciation and amortization increased from $233,807 in 1999 to $371,249 in 2000. The increase was due to depreciation on new equipment purchased late in the years of 1999 and an increase in depletion expense of $97,000 due to a change in estimate resulting from changes in reserves.
General and administrative expenses have increased from $1,961,348 in 1999 to $2,602,311 in 2000, to $2,957,871 in 2001. The increases from 2000 to 2001 are attributable to an increase in insurance (approximately $400,000) to expand coverage including blowout insurance and the addition of Company providing medical insurance for employees in 2001. The increase of $640,963 from 1999 to 2000 was due primarily to an increase in additional personnel, consultants and increased engineering services for reserve evaluations.
Interest expense for 2001 increased significantly over 1999 and 2000 levels. This increase is due to additional interest cost associated with financing for the completion of Phase II of the Company's 65 mile pipeline. This increase was reduced by interest cost of approximately $148,000 which was capitalized in the first 3 months of 2001 during construction of the pipeline and $128,000 in 2000. Interest expense remained consistent from 1999 to 2000.
Public relations cost increased ($187,253) in 2001 as compared to 2000 levels due to cost associated with producing the annual report, the proxy statement, and press releases. Public relations cost in 2000 was only slightly higher ($20,134) than 1999 cost.
Professional fees decreased in 2001 from 2000 levels and are consistent with 1999 levels due to a charge in 2000 of $242,000 for stock options issued in 2000 to non-employees.
Dividends on preferred stock has increased from $119,347 in 1999 to $257,557 in 2000 to $391,183 in 2001 as a result in the increase in preferred stock outstanding.
LIQUIDITY AND CAPITAL RESOURCES
On November 8, 2001, the Company signed a credit facility agreement (the "Credit Agreement") with the Energy Finance Division of Bank One, N.A. in Houston Texas ("Bank One") whereby Bank One extended to the Company a revolving line of credit of up to $35 million. The interest rate on the line of credit is the Bank One base rate plus one quarter percent which at the time of closing was 5.25%. The initial borrowing base under the Credit Agreement was $10 million. The initial borrowing base was determined by Bank One according to its own internal and unspecified formulas. Under the terms of the Credit Agreement, the initial borrowing base is to be reviewed and updated periodically by Bank One based on its review, at various specified times, of reserve analyses of the Company's proved oil and gas reserves, such as the report prepared by Ryder Scott as of December 31, 2001. See, "Item 2 Description of Property - Reserve Analysis." No increase will occur beyond the initial borrowing base of $10 million unless the Company's proved oil and gas reserves increase to such a level that Bank One in its sole discretion according to its own internal formulas determines that such an increase in the credit facility is warranted. Conversely, the initial credit base may be decreased if Bank One upon review of reserve analysis at times as specified in the Credit Agreement in its sole discretion, according to its own internal formulas, determines that such a decrease in the credit facility is warranted. In addition, the terms of the Credit Agreement provides that the calculation of the borrowing base includes an "equity cushion," in an unspecified amount, intended to protect Bank One from difficulties in evaluating, liquidating, or collecting against oil and gas properties stated to be subject to rapid deterioration in value and inherently incapable of being accurately evaluated.
On November 9, 2001, funds from the Bank One credit line were used to (1) satisfy existing indebtedness on the Company's Kansas Properties ($1,427,309.25); (2) repay the internal financing provided by Directors and shareholders of the Company for the completion of the Company's 65 mile intrastate pipeline ($3,895,490.83); (3) prepay a note due to Spoonbill, Inc. for funds borrowed by the Company for working capital ($1,080,833.34); (4) prepay a note due to Malcolm E. Ratliff, the Company's Chief Executive Officer, for purchase by the Company of a drilling rig and related equipment ($1,003,844.44); and, (5) prepay the remaining balance of a loan made to the Company for working capital by Edward W.T.Gray III, a former Director of the Company, due on December 31, 2001 ($304,444.44). All of these obligations incurred interest at a rate substantially greater than the rate being charged by Bank One under the Credit Agreement. Together with attorneys fees, mortgage taxes in Tennessee and Kansas and related fees the total drawn down on November 9, 2001 from the credit facility was $7,901,776.65. As of the date of this Report, the principal balance of the loan under the Credit Agreement is $9,101,776.66.
On or about April 5, 2002, the Company received a notice from Bank One stating that it had re-determined and reduced the borrowing base under the Credit Agreement to $3,101,766.66. The notice did not provide any explanation why the reduction was made or as to how the reduction was calculated. As a result of the reduction of the borrowing base, Bank One has demanded that the Company satisfy the difference between the principal balance of the loan under the Credit Agreement ($9,101,776.66) and the newly reduced current borrowing base ($3,101,776.66) within thirty days of the receipt of the notice advising the Company of the reduction of the borrowing base.
The Company has notified Bank One that it strongly disagrees that the re-determination of the borrowing base was proper under the terms of the Credit Agreement. It is the contention of the Company that a re-determination of the borrowing base can only be made in accordance with specific schedules provided for in the Credit Agreement. The Company is required to submit its first analysis of proved reserves to Bank One by December 1, 2002 for purposes of determining the borrowing base. Thereafter, reserve analysis are to be reviewed every six months. The schedule of reserve reports required by the Credit Agreement upon which such re-determinations are to be based also specifically sets up a procedure involving an automatic monthly payment of $200,000 effective as of February 1, 2002 to be applied against the borrowing base.
The re-determination of the borrowing base made on April 5, 2002 by Bank One is not in accordance with the expressed schedule in the Credit Agreement which provides that the next re-determination date is after December 1, 2002, and which would allow for updated reserve analysis reports reflecting the attendant adjustments to the Company's proved reserves as new wells come into production and existing wells are re-worked in its Swan Creek Field before any re-determination of the borrowing base could be made. Such updated reserve analysis reports also would reflect the substantial current increases in oil and gas prices from the substantially lower year-end oil and gas prices used to evaluate the Company's reserves in the Company's most recent reserve analysis report prepared by Ryder Scott as of December 31, 2001. The borrowing base provisions of the Credit Agreement also permit Bank One to require the Company to provide an analysis by certified engineers on ninety days notice if it has concerns regarding the status of the reserves of the producing properties. This was not done. Such a procedure would be the proper way for Bank One to have proceeded if it had such concerns. Finally, the Company views Bank One's position under the Credit Agreement to be fully secured by the properties the Company owns in Kansas and Tennessee. The values of these properties far exceeds the original initial borrowing base under the Credit Agreement. This fact further underscores the impropriety of the attempted recent reduction of the borrowing base and that such action is clearly unjustified by the terms and intent of the Credit Agreement. The Company is seeking to have Bank One withdraw its April 5, 2002 re-determination of the borrowing base.
In an effort to resolve this dispute amicably, alternatively, the Company has requested Bank One to allow it to reduce the difference between the principal balance of the loan and the reduced borrowing base over a period of time. If the Company's request is honored, it is believed that through a combination of the use of the Company's cash flow and outside equity or
loan financing it will be able to resolve any disputes with Bank One. However, any substantial increase of the pay down of the loan over the $200,000 per month presently being paid will significantly impair the Company's ability to repair its current problem wells and to drill new wells. In the event the Company is unable to resolve its differences with Bank One, the Company might be held to be in default of its obligation to Bank One, which would enable Bank One to call the entire loan. In such event, the Company would vigorously oppose any such action by Bank One. If Bank One should be successful, the Company believes that it would be able to procure alternative debt financing and equity funding to enable to meet its obligation. The Company is hopeful that it will be able to work out a satisfactory arrangement with Bank One.
Even if the Company is able to reach an agreement with Bank One as to the amount of its current borrowing base and the pay-off of any difference between that borrowing base and the principal balance of the loan, unless the Company is able to increase production from its Swan Creek Field and as a result, increase the calculation of proven oil and gas reserves it will not be able to increase its borrowing base under the Bank One Credit Agreement beyond the initial $10 million borrowing base. Although the Company is hopeful it will be able to increase production and its proven reserves, there are no assurances that the Company will be able to do so to an amount sufficient to allow it to borrow additional sums from Bank One beyond the current borrowing base. In the event that the Company is unable to increase the amount of its current borrowing base under the Bank One Credit Agreement, it will be forced to seek other options to obtain the funding necessary to meet its obligation to reduce the Bank One loan and to satisfy all of its current and future cash requirements, including funds necessary to re-work existing wells and continue the drilling program in the Swan Creek Field. Such options would include debt financing, sale of equity interests in the Company, a joint venture arrangement, the sale of oil and gas interests, etc. The inability of the Company to obtain the necessary cash funding on a timely basis would have an unfavorable effect on the Company's financial condition and would require the Company to materially reduce the scope of its operating and investing activities.
The Company plans to shortly offer for sale by private placement a new series of cumulative convertible preferred stock. The additional capital raised from such offering will be used to provide funds for re-payment to Bank One of the Loan Excess, to pay for re-working of wells and continuing the drilling program in the Swan Creek Field to increase production and to provide working capital. There can be no assurances that the Company will be able to sell such preferred stock or, if it is able to do so, the proceeds of the sale of the new series of cumulative convertible preferred stock will be sufficient to accomplish these purposes.
As a result of Bank One's reduction of the borrowing base and the corresponding demand for payment of the difference between the amount of the balance of the loan and the reduced borrowing base, combined with the fact that the Company is still in the early stages of its oil and gas operating history during which time it has a history of losses from operations and has an accumulated deficit of $24,115,382 and a working capital deficit of $6,326,204 as of December 31, 2001, the Company's independent certified public accountants have indicated in their report on the Consolidated Financial Statements that these circumstances contribute to uncertainty over the Company's ability to continue as a
going concern. The Company's ability to continue as a going concern depends upon its ability to obtain long-term debt or raise capital to satisfy its cash flow requirements. See, "Report of Independent Auditors" and "Notes to Consolidated Financial Statements - Note 2 - Going Concern Uncertainty." Management believes based upon the Company's substantial assets and proved reserves; its expectation that production and revenues from its Swan Creek Field will increase by the end of fiscal 2002; and, the current increase in oil and gas prices, that the Company will be able to obtain the long-term debt or raise capital to enable it to continue in business.
As of December 31, 2001, the Company had total stockholders' equity of $14,991,847 on total assets of $32,128,245. The Company has a net working capital deficiency at December 31, 2001 of $6,326,204 as compared to a net deficiency of $708,317 at December, 2000. This working capital deficiency arises primarily from the acceleration of $6,000,000 of the credit facility debt discussed above.
Net cash used in operating activities decreased from $820,615 in 2000 to $221,176 in 2001. The Company's net loss in 2001 increased to $2,262,787 from $1,541,884 in 2000. The impact on cash used due to the net loss for 2001 was primarily offset by non-cash depletion, depreciation and amortization of $1,849,963 and non-cash compensation and services paid by issuance of equity instruments of $92,253. Cash flow from working capital items in 2001 was $232,338 as compared to $66,020 in 2000. This resulted from increases in accounts payable of $191,702, and decreases in inventory of 91,981 and accounts receivable of $3,814, partially offset by a decrease in accrued interest payable of $2,519 and a decrease in accrued liabilities of $52,640. Net cash used in operating activities decreased from $2,587,003 in 1999 to $820,615 in 2000. This was primarily due to the fact that the Company's net loss in 2000 decreased to $1,541,884 from a net loss in 1999 of $2,671,923. The impact on cash used due to the net loss for 2000 was partially offset by non-cash depletion, depreciation and amortization of $371,249 and non-cash compensation and services paid by the issuance of equity instruments of $284,000. Cash flow from working capital items in 2000 was $66,020 as compared to uses of cash flow of $353,387 in 1999. This reflects increases in accounts payable of $364,553 and accrued interest payable of $135,435, partially offset by an increase in accounts receivable of $301,421, and a decrease in other accrued liabilities of $140,955.
Net cash used in investing activities amounted to $9,408,684 for 2001 as compared to $8,936,863 for 2000. The large increase in net cash used for investing activities during 2001 was primarily attributable to additions to oil and gas properties of $4,821,883 in 2001 as compared to $1,456,996 in 2000. This was offset by a reduction in expenditures used for the construction of Phase II of the pipeline of $4,213,095 due to its completion in 2001 compared to $6,834,196 in 2000 and a reduction of expenditures used for additions to other property and equipment of $285,722 in 2001 as compared to $1,276,783 in 2000.
Net cash used in investing activities amounted to $8,936,863 for 2000 compared to net cash used in the amount of $1,892,294 for 1999. The large increase in net cash used for
investing activities during 2000 was primarily attributable to the construction of Phase II of the pipeline of $6,834,196 in 2000 as compared to $193,633 in 1999, additions to oil and gas properties of $1,456,996 in 2000 as compared to $788,029 in 1999 and additions to other property and equipment of $1,276,783 in 2000 as compared to $256,045 in 1999.
Net cash provided by financing activities amounted to $8,419,336 in 2001 as compared to $ 10,940,863 in 2000. The primary sources of financing include proceeds from borrowings of $10,442,068 in 2001 as compared to $6,493,563 in 2000, private placements of common stock of $3,900,000 in 2001 as compared to $4,425,713 in 2000, convertible redeemable preferred stock of $1,591,150 in 2001 as compared to $2,000,000 in 2000 and proceeds from exercise of options of $2,341,000 in 2001 as compared to $180,013 in 2000. The primary use of cash in financing activities was the repayment of borrowings of $8,833,325 in 2001 as compared to $1,720,856 in 2000.
Net cash provided by financing activities amounted to $10,940,863 for 2000 as compared to $3,896,693 for 1999. The primary sources of financing include proceeds from borrowings of $6,493,563 in 2000 as compared to $2,119,023 in 1999, private placements of common stock of $4,425,700 in 2000 as compared to $2,771,722 in 1999 and convertible redeemable preferred stock of $2,000,000 in 2000 as compared to $1,188,900 in 1999. The primary use of cash in financing activities was the repayment of borrowings of $1,720,856 in 2000 as compared to $2,383,605 in 1999.
CRITICAL ACCOUNTING POLICIES
The Company's accounting policies are described in the Notes to Consolidated Financial Statements in Item 8 of this Report. The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company's financial statements and the uncertainties that could impact the Company's results of operations, financial condition and cash flows.
CONTINGENCIES
The Company accounts for contingencies in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards ("SFAS") No. 5, "Accounting Contingencies." SFAS No. 5 requires that we record an estimated loss from a loss contingency when information available prior to the issuance of the Company's financial statements indicate that it is probable an asset has been impaired or a liability has been incurred at the date of the
financial statements and the amount of the loss can be reasonably estimated. Accounting for contingencies such as environmental, legal and income tax matters requires management of the Company to use its judgment. While management of the Company believes that the Company's accrual for these matters are adequate, if the actual loss from a loss contingency is significantly different from the estimated loss, the Company's results of operations may be over or understated. The primary area in which the Company has to estimate contingent liabilities is with respect to legal actions brought against the Company. See. Item 3 - Legal Proceedings."
FULL COST METHOD OF ACCOUNTING
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and non-productive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, daily rentals and the costs of drilling, completing and equipping oil and gas wells. The Company capitalized $4,821,883, $1,456,996 and $788,029 of these costs in 2001, 2000 and 1999, respectively. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs.
OIL AND GAS RESERVES
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.
The Company's proved oil and gas reserves as at December 31, 2001 were estimated by Ryder Scott, L.P., Petroleum Consultants. The Company's discounted present value of its proved oil and gas reserves requires subjective judgments. Estimates of the Company's reserves are in part forecasts based on engineering data, projected future rates of production and timing of future expenditures. The process of estimating oil and gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. The passage of time provides more qualitative information regarding estimates of reserves and revisions are made to prior estimates to reflect updated information. Given the volatility of oil and gas prices, it is also reasonably possible that the Company's estimate of discounted net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline
significantly as they did in 2001, this will result in a reduction of the valuation of the Company's reserves. This past year, Ryder Scott based on initial production results and the sharp decline of oil and gas prices, significantly reduced the Company's estimated reserves of gas in the Swan Creek Field from its reserve report for the year ended December 31, 2000. See, "Item 2 - - Description of Property - Reserve Analysis".
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivatives and Hedging Activities," effective January 1, 2000. SFAS No. 133 ( as amended, by SFAS No. 137 and No. 138) requires a company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a fair value hedge, changes in the fair value of the hedged assets, liabilities or firm commitments are recognized through earnings. If the derivative is a cash flow hedge the effective portion of changes in the fair value of the derivative are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings. The adoption of SFAS no. 133, as amended, did not have a material impact on the Company's consolidated financial statements for the year ending December 31, 2001.
In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" and SFAS No.142, "Goodwill and Other Intangible Assets". SFAS No. 141 addresses the initial recognition and measurement of goodwill and other intangible assets acquired in a business combination and SFAS No. 142 addresses the initial recognition and measurement of intangible assets acquired outside of a business combination whether acquired individually or with a group of other assets. These standards require all future business combinations to be accounted for using the purchase method of accounting. Goodwill will no longer be amortized but instead will be subject to impairment tests at least annually. The Company would have been required to adopt SFAS No. 141 on July 1, 2001, and to adopt SFAS 142 on a prospective basis as of January 1, 2002. The Company has not effected a business combination and carries no goodwill on its balance sheet; accordingly, the adoption of these standards is not expected to have an effect on the Company's financial position or results of operations.
In June 2001, the Financial Accounting Standards Board approved the issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS 143 establishes accounting standards for the recognition and measurement of legal obligations associated with the retirement of tangible long-lived assets and requires recognition of a liability for an asset retirement obligation in the period in which it is incurred. The provisions of this statement are effective for financial statements issued for fiscal years beginning after June 15, 2002. The adoption of this statement is not expected to have a material impact on the Company's financial position or results of operations.
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and expands on the guidance provided by SFAS No. 121 with respect to cash flow estimations. SFAS No. 144 becomes effective for the Company's fiscal year beginning January 1, 2002. There will be no current impact of adoption on its financial position or results of operations.
ITEM 7A
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
COMMODITY RISK
The Company's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of $14.00 per barrel to a high of $27.73 per barrel during 2001. Gas price realizations ranged from a monthly low of $1.68 per Mcf to a monthly high of $9.80 per Mcf during the same period.
The Company entered into hedge agreements on December 28, 2001 on notional volumes of oil and natural gas production for the first seven months of 2002 in order to manage some exposure to oil and gas price fluctuations. Realized gains or losses from the Company's price risk management activities will be recognized in oil and gas production revenues when earned since the Company's positions are not considered hedges for financial reporting purposes. Notional volumes associated with the Company's derivative contracts are 27,000 barrels and 630,000 MMBtu's for oil and natural gas, respectively. As these activities are not effective until fiscal 2002, no gains or losses were recognized for the year ended December 31, 2001. The Company does not generally hold or issue derivative instruments for trading purposes.
At December 31, 2001, the Company's open natural gas and crude oil price swap positions are not considered to have a material fair value. Assuming natural gas production and sales volumes remain consistent at December 2001 levels during the entire year of fiscal 2002, management believes that a 10 percent decrease in unhedged natural gas prices would reduce the Company's natural gas revenues by approximately $41,610 on an annual basis. Assuming crude oil production and sales volumes remain consistent at December 2001 levels during the entire year of fiscal 2002, management believes that a 10 percent decrease in unhedged crude oil prices would reduce the Company's crude oil revenues by approximately $208,840 on an annual basis.
INTEREST RATE RISK
At December 31, 2001, the Company had debt outstanding of approximately $10.3 million. The interest rate on the revolving credit facility of $9.1 million is variable based on the financial institution's prime rate plus 0.25%. The remaining debt of $1.2 million has fixed interest rates ranging from 7.5% to 11.95%. As a result, the Company's annual interest costs in 2002 would fluctuate based on short-term interest rates on approximately 88% of its total debt outstanding at December 31, 2001. The impact on interest expense and the Company's cash flows of a 10 percent increase in the financial institution's prime rate (approximately .5 basis points) would be approximately $45,500, assuming borrowed amounts under the credit facility remain at $9.1 million. The Company did not have any open derivative contracts relating to interest rates at December 31, 2001.
FORWARD-LOOKING STATEMENTS AND RISK
Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company's control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Company's financial position, results of operations and cash flows.
ITEM 8
ITEM 8 FINANCIAL STATEMENTS
The financial statements and supplementary data commence on page.
ITEM 9
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable
PART III
ITEM 10
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
IDENTIFICATION OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the names of all current directors and executive officers of the Company. These persons will serve until the next annual meeting of stockholders (to be held at such time as the Board of Directors shall determine) or until their successors are elected or appointed and qualified, or their prior resignations or terminations.
Date of Initial Positions Election or Name Held Designation - ------------------- -------- -------
Joseph E. Armstrong Director 3/13/97 4708 Hilldale Drive Knoxville, TN 37914
Benton L. Becker Director 8/31/99 1497 Lacosta Drive East Pembrook Pines, FL 33027
Bill L. Harbert Director 4/2/02 820 Shaders Creek Pkway Birmingham, AL 35209
Robert D. Hatcher, Jr Director 8/8/00 107 Golden Gate Lane Oak Ridge, TN 37830
Malcolm E. Ratliff Chairman of the 4/21/98 2100 Scott Lane Board; Chief Executive Knoxville, TN 37922 Officer
Charles Stivers Director 9/28/01 420 Richmond Road Manchester, KY 40962
Harold G. Morris, Jr President 10/19/99 153 Chuniloti Way Loudon, TN 37774
Mark A. Ruth Chief Financial 12/14/98 9400 Hickory Knoll Lane Officer Knoxville, TN 37922
Robert M. Carter President Tengasco 6/1/98 760 Prince George Parish Drive Pipeline Corporation Knoxville, TN 37931
Cary V. Sorensen General Counsel; 07/9/99 509 Bretton Woods Dr. Secretary Knoxville, TN 37919
Sheila Sloan Treasurer 12/4/96 121 Oostanali Way Loudon, TN 37774
Jeffrey R. Bailey Chief Geological 3/1/02 2306 West Gallaher Ferry Engineer Knoxville, TN 37932
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
In fiscal 2001, Joseph Armstrong and Benton L. Becker, who are Directors of the Company, each failed to timely file one Form 4 Report each involving one transaction. Sanford E. McCormick who was a Director of the Company until March 15, 2001 also failed to timely file one Form 4 Report involving one transaction in 2001. In addition, Mr. Becker, as well as Robert D. Hatcher, Jr., also a Director of the Company, each timely filed a Form 5 Report for December 2001 which each reported one transaction that should have been reported on an earlier Form 4 Report. Harold G. Morris, Jr., President of the Company filed a Form 4 Report in 2001 that inadvertently was not filed in 1999 reporting one transaction. Malcolm E. Ratliff, the Company's Chief Executive Officer and a Director of the Company, recently filed a timely Form 5 Report for December 2001 which indicated that he failed to timely file eight Form 4 Reports for 2001 involving 46 transactions. Mr. Ratliff also recently filed a Form 5 Report for December 2000 which should have been filed in 2001 indicating he had failed to timely file five Form 4 Reports that were to be filed in 2000 involving 26 transactions. These deficiencies have all been cured.
BUSINESS EXPERIENCE
DIRECTORS
Joseph Earl Armstrong is 45 years old and a resident of Knoxville, Tennessee. He is a graduate of the University of Tennessee and Morristown College where he received a Bachelor of Science Degree in Business Administration. From 1988 to the present, he has been an
elected State Representative for Legislative District 15 in Tennessee. From 1994 to the present he has been in charge of government relations for the Atlanta Life Insurance Co. From 1981 to 1994 he was a District Manager for the Atlanta Life Insurance Co.
Benton L. Becker is 64 years old. In 1960 he received a B.A. degree from the University of Maryland. In 1966 he graduated from the American University Law School in Washington, D.C. He is currently engaged in the private practice of law in Coral Gables, Florida and Washington D.C., while regularly serving as a Distinguished Lecturer on constitutional law at the University of Miami in Coral Gables, Florida. His past positions include serving as a trial attorney for the U. S. Department of Justice, the Dade County, Florida State's Attorney Office and a Professor of Law at the University of Miami School of Law. During his career Mr. Becker has represented the U.S. House of Representatives, the Republican National Committee and President Gerald R. Ford. In 1976 Mr. Becker represented Commonwealth Oil and Refining Company of Puerto Rico in a Federal trial and Appellate action against Texaco, Exxon and Mobil and obtained a multi-million dollar judgment for Commonwealth Oil. In 1980 he served as Board Chairman for Appalachian Oil and Gas. From June 5, 1995 to January 30, 1997 he served as Chairman of the Company's Board of Directors.
Bill L. Harbert is 78 years old. He earned a B.S. degree in civil engineering from Auburn University in 1948. In 1949 he was one of the founders of Harbert Construction Company. He managed that company's construction operations, both domestic and foreign, and served as its Executive Vice-President until 1979. From 1979 until July, 1990 he served as President and Chief Operating Officer and from July 1990 through December 1991 he served as Vice Chairman of the Board of Harbert International, Inc. He then purchased a majority of the international operations of Harbert International, Inc. and formed Bill Harbert International Construction, Inc. He served as Chairman and Chief Executive Officer of that corporation until retiring from the company in 2000. Mr. Harbert's companies built pipeline projects in the United States and throughout the world. They also built many other projects including bridges, commercial buildings, waste water treatment plants, airports, including an air base in Negev, Israel and embassies for the United States government in, among other places, Tel Aviv, Hong Kong, and Baku. Mr. Harbert has also served as president (1979) and Director (1980) of the Pipe Line Contractors Association, USA and for seven years as Director, Second Vice-President and First Vice-President (2001-2002) of the International Pipe Line Contractors Association. Mr. Harbert has been active in service to a variety of business associations, charities and the arts in the Birmingham area for many years.
Robert D. Hatcher, Jr. is 61 years old. He earned B.A. and M.S. degrees from Vanderbilt University in 1961 and 1962, with majors in geology and chemistry and a minor in mathematics. He earned a Ph.D. degree in 1965 from the University of Tennessee (Knoxville), in structural geology with a minor in chemistry. Thereafter, he worked with Humble Oil and Refining Company (now Exxon USA) for one year. In 1966 he accepted a faculty position at Clemson University where he taught and conducted research in the Appalachians until 1978. In 1978 Dr. Hatcher moved to Florida State University where he stayed until 1980. He then taught at the University of South Carolina until 1986. In 1986, Dr. Hatcher accepted a chair as a University
of Tennessee/Oak Ridge National Laboratory Distinguished Scientist, which position he currently maintains. He has served on the Council (Board of Directors) of the Geological Society of America (a not-for-profit corporation) from 1981-1983 and again from 1992-1994 when he served on the Executive Committee and as President (1993). He is currently serving on the Board of Trustees of the Geological Society of America Foundation. He served on the Executive Committee of the American Geological Institute (a not-for-profit corporation) from 1995-1997 and as President in 1996. He has also served on the National Academy of Sciences Board on Radioactive Waste Management and on several National Research Council, as well as on Federal Advisory Committees for the Nuclear Regulatory Commission and the Department of the Interior. He served as Science Advisor to South Carolina Governor Richard Riley for Off-Site Disposal of Radioactive Waste from 1984 through 1986. He was honored in 1997 by the I.C. White Award and in 1998 by being made an honorary citizen of West Virginia, both recognizing his long-term contributions to Appalachian geology. He is a Fellow in the American Association for the Advancement of Science. Dr. Hatcher is the author of over 150 journal articles and several texts and monographs, including a structural geology textbook which has been used in some 85 colleges and universities. He has also served as an Editor of the Geological Society of America Bulletin.
Malcolm E. Ratliff is 54 years old. He attended the University of Mississippi and since 1971 has been involved in the oil and gas business with 30 years of hand-on experience in drilling and development of oil and gas wells, seismic studies and laying pipe onshore and offshore. Mr. Ratliff holds numerous oil and gas investments in companies throughout the United States. In April, 1995 he was instrumental in the founding of the Company and served as a consultant to the Company's Board of Directors. In March, 1997 he became the Chief Executive Officer of the Company and also acted as interim President of the Company until he resigned in March, 1998 for health reasons. On April 21, 1998 at the request of the Company's Board of Directors, Mr. Ratliff agreed to return to the management of the Company as its Chief Executive Officer. He has served as Chairman of the Company's Board of Directors since June 19, 1998.
Charles M. Stivers is 39 years old. He is a Certified Public Accountant with 18 years accounting experience. In 1984 he received a B.S. degree in accounting from Eastern Kentucky University. From 1983 through July 1986 he served as Treasurer and CEO for Clay Resource Company. From August 1986 through August 1989 he served as a senior tax and audit specialist for Gallaher and Company. From September 1989 to date he has owned and operated Charles M. Stivers, C.P.A., a regional accounting firm. The Firm specializes in the oil and gas industry and has clients in eight states. The oil and gas work performed by the Firm includes all forms of SEC audit work, SEC quarterly financial statement filings, oil and gas consulting work and income tax services. The Firm has also represented oil and gas companies with respect to Federal and State income tax disputes in 15 states over the past 12 years. In September 2001, he was elected as a director of the Company and is the chairman of the Company's audit committee.
OFFICERS
Harold G. Morris, Jr. is 53 years old. In 1970 he received a B.S. Degree in
accounting from St. Peter's College in Jersey City, New Jersey. He is a member of the National Association of Certified Fraud Examiners. From 1970 to 1975 he worked in New York, New York for Main LaFrentz & Co., Certified Public Accountants where he was a senior auditor for the firm's largest client, CPC International, Inc. He was in charge of International Worldwide Consolidation, along with the translation of multi-national currencies (Asian, European and Canadian) into dollars. His experience includes audits of many industries including the audit of Wall Street brokerage firms. From 1975 to 1980 he worked for Foster Wheeler Corporate headquarters in Livingston, New Jersey as Chief Internal Auditor where he assisted in all corporate mergers and acquisitions. During this time he was promoted to CEO and CFO of Copeland Systems, Inc. and then Treasurer/Controller of Chemical Separations Corp. in Oak Ridge Tennessee, both of which were wholly owned subsidiaries of Foster Wheeler. From 1980 to 1983, Mr. Morris was Group Controller of Macawber Engineering's U.S., Japan, England and Australian operations. From 1985 to 1999 he was Controller/Ass't. Secretary for W. J. Savage Co., Inc. in Knoxville, Tennessee. He joined the Company as Vice-President of Finance on October 19, 1999. On August 8, 2000 he was elected as Executive Vice-President of the Company and on August 1, 2001 he was elected as President of the Company.
Mark A. Ruth is 43 years old. He is a certified public accountant with 21 years accounting experience. He received a B.S. degree in accounting with honors from the University of Tennessee at Knoxville. He has served as a project controls engineer for Bechtel Jacobs Company, LLC; business manager and finance officer for Lockheed Martin Energy Systems; settlement department head and senior accountant for the Federal deposit Insurance Corporation; senior financial analyst/internal auditor for Phillips Consumer Electronics Corporation; and, as an auditor for Arthur Andersen and Company. From December 14, 1998 to August 31, 1999 he served as the Company's Chief Financial Officer. On August 31, 1999 he was elected as a Vice-President of the Company and on November 8, 1999 he was again appointed as the Company's Chief Financial Officer.
Robert M. Carter is 65 years old. He attended Tennessee Wesleyan College and Middle Tennessee State College between 1954 and 1957. For 35 years he was an owner of Carter Lumber & Building Supply Company and Carter Warehouse in Loudon County, Tennessee. He has been with the Company since 1995 and during that time has been involved in all phases of the Company's business including pipeline construction, leasing, financing, and the negotiation of acquisitions. Mr. Carter was elected Vice-President of the Company in March, 1996, as Executive Vice-President in April 1997 and on March 13, 1998 he was elected as President of the Company. He served as President of the Company until he resigned from that position on October 19,1999. On August 8, 2000 he again was elected as President of the Company and served in that capacity until July 31, 2001. He has served as President of Tengasco Pipeline Corporation, a wholly owned subsidiary of the Company, from June 1, 1998 to the present.
Cary V. Sorensen is 53 years old. He is a 1976 graduate of the University of Texas School of Law and has undergraduate and graduate degrees form North Texas State University and Catholic University in Washington, D.C. Prior to joining the Company in July, 1999, he had been continuously engaged in the practice of law in Houston, Texas relating to the energy industry
since 1977, both in private law firms and a corporate law department, most recently serving for seven years as senior counsel with the litigation department of Enron Corp. before entering private practice in June, 1996. He has represented virtually all of the major oil companies headquartered in Houston and all of the operating subsidiaries of Enron Corp., as well as local distribution companies and electric utilities in a variety of litigated and administrative cases before state and federal courts and agencies in five states. These matters involved gas contracts, gas marketing, exploration and production disputes involving royalties or operating interests, land titles, oil pipelines and gas pipeline tariff matters at the state and federal levels, and general operation and regulation of interstate and intrastate gas pipelines. He has served as Legal Counsel of the Company since July 9, 1999 and as Secretary of the Company since March 4, 2002.
Sheila F. Sloan is 46 years old. She graduated from South Lake High School located in St. Clair Shores, Michigan in 1972. From 1981 to 1985 she worked as a purchasing agent for Sequoyah Land Company located in Madisonville, Tennessee. From 1990 to 1995 she managed the Form U-3 Weight Loss Centers in Knoxville, Tennessee. She has been with the Company since January 1996. On December 4, 1996 she was elected as the Company's Treasurer.
Jeffrey R. Bailey is 44 years old. He graduated in 1980 from New Mexico Institute of Mining and Technology with a B.S. degree in Geological Engineering. Upon graduation he joined Gearhart Industries as a field engineer working in Texas, New Mexico, Kansas, Oklahoma and Arkansas. Gearhart Industries later merged with Halliburton Company. In 1993 after 13 years working in various field operations and management roles primarily focused on reservoir evaluation, log analysis and log data acquisition he assumed a global role with Halliburton as a Petrophysics instructor in Fort Worth Texas. His duties were to teach Halliburton personnel and customers around the world log analysis, competition technology and to review anayltical reservoir problems. In this role Mr. Bailey had the opportunity to review reservoirs in Europe, Latin America, Asia Pacific and the Middle East developing a special expertise in carbonate reservoirs. In 1997 he became technical manager for Halliburton in Mexico focusing on finding engineering solutions to the production challenges of large carbonate reservoirs in Mexico. He joined the Company as its Chief Geological Engineer on March 1, 2002.
COMMITTEES
The Company's Board has operating stock option, audit, compensation and frontier exploration committees. In fiscal 2001 Messrs. Stivers, Becker and Gray comprised the stock option committee. Messrs. Stivers, Hatcher and Gray comprised the audit committee, Messrs. Armstrong, Becker and Gray were the members of the compensation committee and Messrs. McCormick, Hatcher and Armstrong comprised the frontier exploration committee. The Board also formed a field safety committee consisting of members of the Board and Officers of the Company. That committee in 2001 consisted of Messrs. Ratliff, Armstrong, Carter, Sorensen and Jeffrey Brockman, the field supervisor for the Company's drilling operations.
FAMILY RELATIONSHIPS
There are no family relationships between any of the present directors or executive officers of the Company.
INVOLVEMENT IN CERTAIN LEGAL PROCEEDINGS
To the knowledge of management, during the past five years, no present or former director, executive officer, affiliate or person nominated to become a director or an executive officer of the Company:
(1) Filed a petition under the federal bankruptcy laws or any state insolvency law, nor had a receiver, fiscal agent or similar officer appointed by a court for the business or property of such person, or any partnership in which he or she was a general partner at or within two years before the time of such filing, or any corporation or business association of which he or she was an executive officer at or within two years before the time of such filing;
(2) Was convicted in a criminal proceeding or named subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);
(3) Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him or her from or otherwise limiting his or her involvement in any type of business, securities or banking activities;
(4) Was found by a court of competent jurisdiction in a civil action, by the Securities and Exchange Commission or the Commodity Futures Trading Commission to have violated any federal or state securities law, and the judgment in such civil action or finding by the Securities and Exchange Commission has not been subsequently reversed, suspended, or vacated.
ITEM 11
ITEM 11 EXECUTIVE COMPENSATION
The following table sets forth a summary of all compensation awarded to, earned or paid to, the Company's Chief Executive Officer during fiscal years ended December 31, 2001, December 31, 2000 and December 31, 1999. None of the Company's other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity.
SUMMARY COMPENSATION TABLE
- ---------- (1) Number of shares underlying options has been retroactively adjusted for a 5% stock dividend declared by the Company as of September 4, 2001. 1 Number of shares underlying the unexercised options has been retroactively adjusted for a 5% stock dividend declared by the Company as of September 4, 2001.
OPTION GRANTS FOR FISCAL 2001
No options were granted during fiscal year ended December 31, 2001 to the Chief Executive Officer. None of the Company's other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity during the fiscal year ended December 31, 2001.
AGGREGATE OPTION EXERCISES FOR FISCAL 2001 AND YEAR END OPTION VALUES
No options were exercised during fiscal year ended December 31, 2001 by the Chief Executive Officer. None of the Company's other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity.
The Company adopted an employee health insurance plan in August 2001. The Company does not presently have a pension or similar plan for its directors, executive officers or employees. Management intends to adopt a 401(k) plan and full liability insurance for directors and executive officers in the near future.
- ---------- (7) Number of shares underlying the unexercised options has been retroactively adjusted for a 5% stock dividend declared by the Company as of September 4, 2001.
(8) Unexercised options are in-the-money if the fair market value of the underlying securities exceeds the exercise price of the option. The fair market value of the Common Stock was $8.28 per share on December 31, 2001, as reported by The American Stock Exchange. The exercise price of the unexercised option granted to Malcolm E. Ratliff, the Chief Executive Officer of the Company, is $8.69 per share. As a result, the unexercised options have a negative value.
(9) Value realized in dollars is based upon the difference between the fair market value of the underlying securities on the date of exercise, and the exercise price of the option.
COMPENSATION OF DIRECTORS
The Board of Directors has resolved to compensate members of the Board of Directors for attendance at meetings at the rate of $250 per day, together with direct out-of-pocket expenses incurred in attendance at the meetings, including travel. The Directors, however, have waived such fees due to them as of this date for prior meetings.
Members of the Board of Directors may also be requested to perform consulting or other professional services for the Company from time to time. The Board of Directors has reserved to itself the right to review all directors' claims for compensation on an ad hoc basis.
EMPLOYMENT CONTRACTS
The Company has entered into an employment contract with its Chief Geological Engineer, Jeffrey R. Bailey for a period of one year through February 28, 2003 at an annual salary of $84,000. There are presently no other employment contracts relating to any member of management. However, depending upon the Company's operations and requirements, the Company may offer long term contracts to directors, executive officers or key employees in the future.
COMPENSATION COMMITTEE INTERLOCKING AND INSIDER PARTICIPATION
There are no interlocking relationship between any member of the Company's Compensation Committee and any member of the compensation committee of any other company, nor has any such interlocking relationship existed in the past. No member of the Compensation Committee is or was formerly an officer or an employee of the Company.
ITEM 12
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following tables set forth the share holdings of the Company's directors and executive officers and those persons who own more than 5% of the Company's common stock as of March 1, 2002 with these computations being based upon 10,656,401 shares of common stock being outstanding as of that date and assumes the exercise of 383,250 shares vested under options granted by the Company as of March 1, 2002.
FIVE PERCENT STOCKHOLDERS(10)
NUMBER OF SHARES PERCENT NAME AND ADDRESS TITLE BENEFICIALLY OWNED OF CLASS - ---------------- ----- ------------------ -------- Industrial Resources Stockholder 2,823,987(11) 26.4% Corporation 603 Main Ave Knoxville, TN 37902
Spoonbill, Inc. Stockholder 878,198 8.24% Tung Wai Commercial Bldg 20th Floor 109-111 Gloucester Rd Wanchai, Hong Kong
Bill L. Harbert Stockholder/ 1,077,667 10.11% 820 Shaders Creek Pkwy Director Birmingham, AL 35209
- ---------- (10) Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table reflect the 5% stock dividend declared by the Company for shareholders of record as of September 4, 2001.
(11) Malcolm E. Ratliff, the Chief Executive Officer and Chairman of the Board of Directors of the Company is the sole owner of the outstanding securities and President of Industrial Resources Corporation (" IRC").Ownership of the IRC shares was previously transferred from Malcolm E. Ratliff, due to his illness, to his father, James Ratliff. In December 1999 ownership of the IRC shares was transferred back to Malcolm E. Ratliff from his father. Malcolm E. Ratliff's wife, Linda Ratliff, is the Secretary of IRC. Accordingly, IRC may be deemed to be an affiliate of the Company. James Ratliff, who is the father of Malcolm E. Ratliff, is the sole shareholder and President of Ratliff Farms, Inc. Malcolm E. Ratliff is the Vice-President/Secretary of Ratliff Farms. Malcolm E. Ratliff has voting control of the shares of the Company owned by Ratliff Farms, Inc. Accordingly, Ratliff Farms, Inc. may also be deemed to be an affiliate of the Company. The shares listed here for IRC include 2,299,744 shares owned directly by IRC, 59,171 shares owned directly and an option to purchase 52,500 shares held by Malcolm E. Ratliff, 381,072 shares owned directly by Ratliff Farms, Inc. and 31,500 shares owned directly by a trust of which Linda Ratliff is trustee and the children of Malcolm E. Ratliff are the beneficiaries. The shares listed here do not include shares of the Company owned directly by James Ratliff.
DIRECTORS AND OFFICERS(12)
NUMBER OF SHARES PERCENT NAME AND ADDRESS TITLE BENEFICIALLY OWNED OF CLASS - ---------------- ----- ------------------ -------- Joseph Earl Armstrong Director 51,4502 Less than 1% 4708 Hilldale Drive Knoxville, TN 37914
Benton L. Becker Director 73,7503 Less than 1% 1497 Lacosta Drive East Pembrook Pines, FL 33027
Robert D. Hatcher, Jr Director 52,605(15) Less than 1% 107 Golden Gate Lane Oak Ridge, TN 37830
Bill L. Harbert Director 1,077,667 10.11% 820 Shaders Creek Pkwy Birmingham, AL 35209
Malcolm E. Ratliff Chief Executive 2,823,987(16) 26.4% 2100 Scott Lane Officer; Chairman Knoxville, TN 37922 of the Board
- ---------- (12) Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table reflect the 5% stock dividend declared by the Company for shareholders of record as of September 4, 2001.
(13) Consists of 9,450 shares held directly and an option to purchase 42,000 shares.
(14) Consists of 21,250 shares owned directly and an option to purchase 52,500 shares.
(15) Consists of 105 shares owned directly and an option to purchase 52,500 shares.
(16) Malcolm E. Ratliff, the Company's Chief Executive Officer and Chairman of the Board of Directors, is also the sole shareholder and President of Industrial Resources Corporation ("IRC"). Ownership of the IRC shares was previously transferred from Malcolm E. Ratliff, due to his illness to his father, James Ratliff. In December 1999 ownership of the IRC shares was transferred back to Malcolm E. Ratliff from his father. Linda Ratliff, Malcolm E. Ratliff's wife, is the Secretary of IRC.James Ratliff, who is the father of Malcolm E. Ratliff, is the sole shareholder and president of Ratliff Farms, Inc. Malcolm E. Ratliff is the Vice-President/Secretary of Ratliff Farms, Inc. Malcolm E. Ratliff has voting control over the shares of the Company owned by Ratliff Farms, Inc. The shares listed here include 2,299,744 shares owned directly by IRC, 59,171 shares owned directly and an option to purchase 52,500 shares held by Malcolm E. Ratliff, 381,072 owned directly by Ratliff Farms, Inc. and 31,500 shares owned directly by a trust of which Linda Ratliff is trustee and the beneficiaries are the children of Malcolm E. Ratliff (the "Ratliff Trust"). The shares listed here do not include shares of the Company owned directly by James Ratliff.
Charles M. Stivers Director -0- -0- 420 Richmond Road Manchester, KY 40962
Harold G. Morris, Jr President 61,817(17) Less than 1% 153 Chuniloti Way Loudon, TN 37774
Robert M. Carter President 54,946(18) Less than 1% 760 Prince Georges Parish Tengasco Pipeline Knoxville, TN 37922 Corporation
Mark A. Ruth Chief Financial 36,750(19) Less than 1% 9400 Hickory Knoll Lane Officer Knoxville, TN 37931
Cary V. Sorensen General Counsel; 31,500(20) Less than 1% 509 Bretton Woods Dr. Secretary Knoxville, TN 37919
Sheila F. Sloan Treasurer 17,850(21) Less than 1% 121 Oostanali Way Loudon, TN 37774
Jeffrey R. Bailey Chief Geological -0- -0- 2306 West Gallaher Ferry Engineer Knoxville, TN 37932
All Officers and 4,282,322(22) 38.8% Directors as a group
- ---------- (17) Consists of 5,775 shares held directly, 3,542 shares owned by his wife and an option to purchase 52,500 shares.
(18) Consists of 7,696 shares held directly and an option to purchase 47,250 shares.
(19) Consists of shares underlying an option.
(20) Consists of shares underlying an option.
(21) Consists of 2,100 shares held directly and an option to purchase 15,750 shares.
(22) Consists of shares held directly and indirectly by management, shares held by IRC, shares held by Ratliff Farms, Inc., shares held by the Ratliff Trust and 383,250 shares underlying options.
CHANGES IN CONTROL
Except as indicated below, to the knowledge of the Company's management, there are no present arrangements or pledges of the Company's securities which may result in a change in control of the Company.
ITEM 13
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TRANSACTIONS WITH MANAGEMENT AND OTHERS
Except as set forth hereafter, there have been no material transactions, series of similar transactions or currently proposed transactions, to which the Company or any of its subsidiaries was or is to be a party, in which the amount involved exceeds $60,000 and in which any director or executive officer or any security holder who is known to the Company to own of record or beneficially more than 5% of the Company's common stock, or any member of the immediate family of any of the foregoing persons, had a material interest.
On January 24, 2001, the Stock Option Committee granted an additional option pursuant to the Tengasco, Inc. Stock Incentive Plan to Shigemi Morita, who at the time was a Director of the Company (he subsequently resigned from that position on February 1, 2002 for personal reasons) to purchase 20,000 shares of the Company's common stock for a period of three years at a price of $14.44 per share.
On November 8, 2001, the Company signed a credit facility with the Energy Finance Division of Bank One, N.A. in Houston, Texas whereby Bank One extended to the Company a revolving credit line of up to $35 million. The initial borrowing base under the facility was $10 million. The balance of the borrowing base is to be adjusted upon periodic review by Bank One based upon the Company's oil and gas reserves. The interest rate is the Bank One base rate plus one-quarter percent. On November 9, 2001, funds from the initial borrowing base of $10 million were used by the Company to, among other things, repay the internal financing provided by Directors and shareholders of the Company to complete Phase II of the Company's pipeline in the aggregate amount of $3.85 million of which the sum of $500,000 was loaned by Morita Properties, Inc., an affiliate of Shigemi Morita, who at the time was a Director of the Company, $1,000,000 was loaned by Edward W.T. Gray III, a Director of the Company and $250,000 was loaned by Malcolm E. Ratliff, Chairman of the Board of Directors and Chief Executive Officer of the Company; prepay a purchase money note due to Malcolm E. Ratliff issued in connection with the Company's purchase of a drilling rig and related equipment from Mr. Ratliff in the amount of $1,003,844.44; and, prepay in full the remaining principal of the working capital loan due December 31, 2001 to Edward W.T.Gray III, a Director of the Company, in the amount of $304,444.44. All of these obligations incurred interest at a rate substantially greater than the rate
being charged by Bank One under the Credit Facility. See, "Item 7 - Liquidity and Financial Condition."
In January 2001, Ratliff Farms, Inc. transferred 164,000 of its shares in the Company to James Ratliff, its sole shareholder and President and who is the father of Malcolm E. Ratliff. Malcolm E. Ratliff is the Vice-President/Secretary of Ratliff Farms, Inc. and has voting control over the shares of the Company owned by Ratliff Farms, Inc. He does not have voting control over the shares of the Company owned by James Ratliff, nor are these shares included in determining the number of shares controlled by Malcolm E. Ratliff and/or Industrial Resources Corp. See, "Item 12 - Security Ownership of Certain Beneficial Owners and Management."
INDEBTEDNESS OF MANAGEMENT
No officer, director or security holder known to the Company to own of record or beneficially more than 5% of the Company's common stock or any member of the immediate family of any of the foregoing persons is indebted to the Company.
PARENT OF THE ISSUER
Unless IRC may be deemed to be a parent of the Company, the Company has no parent.
PART IV
ITEM 14
ITEM 14 EXHIBITS AND REPORTS
1. Financial Statements: Consolidated Balance Sheets Consolidated Statements of Loss Consolidated Statements of Stockholders' Equity Consolidated Statements of Cash Flows
2. Exhibits.
(a) - The following documents heretofore filed by the Company with the commission are hereby incorporated by reference herein from:
(i) Registration Statement on Form 10-SB filed with the Commission August 7, 1997 (Registration No. 0-29386)
Exhibit Number and Description
3.1 Initial Articles of Incorporation 3.2 Bylaws 3.3 Articles of Amendment dated April 12, 1966 3.4 Articles of Amendment dated July 12, 1984 3.5 Articles of Amendment dated December 18, 1991 3.6 Articles of Amendment dated September 11, 1992 3.7 Articles of Incorporation of the Tennessee of wholly-owned subsidiary 3.8 Articles of Merger and Plan of Merger (taking into account the formation of the Tennessee wholly-owned subsidiary for the purpose of changing the Company's domicile and effecting reverse split) 5.1 Opinion of Robson & Miller, LLP 10.1(a) Purchase Agreement with IRC 10.1(b) Amendment to Purchase Agreement with IRC 10.1(c) General Bill of Sale and Promissory Note 10.2(a) Compensation Agreement - M. E. Ratliff 10.2(b) Compensation Agreement - Jeffrey D. Jenson 10.2(c) Compensation Agreement - Leonard W. Burningham 10.3 Agreement with The Natural Gas Utility District of Hawkins County, Tennessee 10.4 Agreement with Powell Valley Electric Cooperative, Inc. 10.5 Agreement with Enserch Energy Services, Inc. 16.1 Letter of David T. Thomson, CPA, Regarding Change in Certifying Accountant 16.2 Letter of Charles M. Stivers, CPA, Regarding Change in Certifying Accountant 16.3 Letter of Price-Bednar, LLP, CPA, Regarding Change in Certifying Accountant 23.1 Consent of Charles M. Stivers, CPA 23.2 Consent of David T. Thomson, CPA 23.3 Consent of BDO Seidman, LLP 23.4 Consent of Robson & Miller, LLP 99.1 Beech Creek Lease Schedule 99.2 Wildcat Lease Schedule 99.3 Burning Springs Lease Schedule 99.4 Fentress County Lease Schedule 99.5 Swan Creek Lease Schedule 99.6 Alabama Lease Schedule 99.7 Coburn Engineering Report dated June 18, 1997.
(ii) Amendment No. 1 to the Registration Statement on Form 10-SB filed with the Commission December 11, 1997 (Registration No. 0-29386)
Exhibit Number and Description
5.1 Opinion of Robson & Miller, LLP 23.1 Consent of Charles M. Stivers, CPA 23.3 Consent of BDO Seidman, LLP 23.4 Consent of Robson & Miller, LLP 23.5 Consent of Coburn Petroleum Engineering Co.
(iii) Current Report on Form 8-K, Date of Report, February 27, 1998:
Exhibit Number and Description
2.1 Plan of Acquisition. Agreement dated December 18, 1997 between AFG Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG Energy, Inc.
(iii) Current Report on Form 8-KA, Date of Report, February 27, 1998:
Exhibit Number and Description
Financial Statements of Business Acquired (AFG Energy, Inc.) Independent auditor's report, statement of revenues and direct operating expenses and notes to financial statements of the properties acquired by Tengasco, Inc. from AFG Energy, Inc. Pro Forma Financial Information Pro forma combined statements of loss for year ended December 31, 1997 for Tengasco, Inc. from AFG Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG Energy, Inc.
(iv) Annual Report on Form 10-KSB, Date of Report, April 10, 1998
Exhibit Number and Description
10.6 Teaming Agreement between Operations Management International, Inc. and Tengasco, Inc. dated March 12, 1997
10.7 Agreement for Transition Services between Operations Management
International, Inc. and Tengasco, Inc. regarding thEast Tennessee Technology Park
99.8 Coburn Engineering Report dated February 18, 1997 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy)
99.9 Columbia Engineering Report dated March 2, 1997 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy)
(v) Annual Report on Form 10-KSB, Date of Report, April 14, 1999
Exhibit Number and Description
3.9 Amendment to the Corporate Charter dated June 24, 1998 3.10 Amendment to the Corporate Charter dated October 30, 1998 99.10 Coburn Engineering Report dated February 9, 1999 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy) 99.11 Columbia Engineering Report dated February 20, 1999 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy)
(vi) Current Report on Form 8-K, Date of Report, October 18, 1999:
Exhibit Number and Description
10.9 Amendment Agreement dated October 19, 1999 between Tengasco, Inc. and The Natural Gas Utility District of Hawkins County, Tennessee
(vii) Current Report on Form 8-KA, Date of Report, November 18, 1999:
Exhibit Number and Description
10.10 Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and Eastman Chemical Company
(viii) Annual Report on Form 10-KSB, Date of Report, April 12, 2000
Exhibit Number and Description
3.11 Amendment to the Corporate Charter filed March 17 , 2000 10.11 Agreement between A.M. Partners L.L.C. and Tengasco, Inc. dated October 6, 1999 10.12 Agreement between Southcoast Capital L.L.C. and Tengasco, Inc. dated February 25, 2000
10.13 Franchise Agreement between Powell Valley Utility District and Tengasco, Inc. dated January 25, 2000 10.14 Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March 27, 2000 99.12 Coburn Engineering Report dated March 30, 2000 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy) 99.13 Columbia Engineering Report dated January 31, 2000 (Paper copy filed on Form SE pursuant to continuing hardship granted by Office of EDGAR Policy)
(ix) Current Report on Form 8-K, Date of Report, August 16, 2000:
Exhibit Number and Description
10.15 Loan Agreement between Tengasco Pipeline Corporation and Morita Properties, Inc. dated August 16, 2000.
10.15(a) Promissory note made by Tengasco Pipeline Corporation to Morita Properties, Inc. dated August 16, 2000.
10.15(b) Throughput Agreement between Tengasco Pipeline Corporation and Morita Properties, Inc. dated August 16, 2000.
10.16 Loan Agreement between Tengasco Pipeline Corporation and Edward W.T. Gray III dated August 16, 2000.
10.16(a) Promissory note made by Tengasco Pipeline Corporation to Edward W.T. Gray III dated August 16, 2000.
10.16(b) Throughput Agreement between Tengasco Pipeline Corporation and Edward W.T. Gray III dated August 16, 2000.
10.17 Loan Agreement between Tengasco Pipeline Corporation and Malcolm E. Ratliff dated August 16, 2000.
10.17(a) Promissory note made by Tengasco Pipeline Corporation to Malcolm E. Ratliff dated August 16, 2000.
10.17(b) Throughput Agreement between Tengasco Pipeline Corporation and Malcolm E. Ratliff dated August 16, 2000.
10.18 Loan Agreement between Tengasco Pipeline Corporation and Charles F. Smithers, Jr. dated August 16, 2000.
10.18(a) Promissory note made by Tengasco Pipeline Corporation to Charles F. Smithers, Jr.
10.18(b) Throughput Agreement between Tengasco Pipeline Corporation and Charles F. Smithers dated August 16, 2000.
10.19 Loan Agreement between Tengasco Pipeline Corporation and Nick Nishiwaki dated August 16, 2000.
10.19(a) Promissory note made by Tengasco Pipeline Corporation to Nick Nishiwaki dated August 16, 2000.
10.19(b) Throughput Agreement between Tengasco Pipeline Corporation and Nick Nishiwaki dated August 16, 2000.
(x) S-8 Registration Statement for shares to be purchased pursuant to options granted pursuant to the Tengasco, Inc. Stock Incentive Plan dated October 25, 2000:
Exhibit Number and Description
4.1 Tengasco, Inc. Incentive Stock Plan
5.1 Opinion of Robson Ferber Frost Chan & Essner, LLP
23.1 Consent of BDO Seidman, LLP
23.2 Consent of Robson Ferber Frost Chan & Essner, LLP contained in Exhibit No. 5.1
(xi) Annual Report on Form 10-KSB, Date of Report, April 10, 2001
Exhibit Number and Description
10.19 Memorandum Agreement between Tengasco, Inc. and The University of Tennessee dated February 13, 2001
10.20 Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems Inc. dated March 30, 2001
99.14 Ryder Scott Report
99.14(a) Consent of Ryder Scott Company
(xii) Quarterly Report on Form 10-Q, Date of Report, April 10, 2001
Exhibit Number and Description
10.21 Reducing Revolving Line of Credit Up to $35,000,000 from Bank One, N.A. to Tengasco, Inc., Tennessee Land & Mineral Corporation and Tengasco Pipeline Corporation dated November 8, 2001
The following exhibits are filed herewith:
99.15 Ryder Scott Report dated March 28, 2002
99.15(a) Consent of Ryder Scott Company
21 List of Subsidiaries
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: April 19, 2002
TENGASCO, INC. (Registrant)
By: s/ MALCOLM E. RATLIFF --------------------- Malcolm E. Ratliff, Chief Executive Officer
By: s/ MARK A. RUTH --------------- Mark A. Ruth, Principal Financial and Accounting Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.
Signature Title Date
s/ MALCOLM E. RATLIFF Chief Executive Officer; April 19, 2002 - ------------------------ Chairman of the Board Malcolm E. Ratliff of Directors
s/ JOSEPH EARL ARMSTRONG Director April 18, 2002 - ------------------------ Joseph Earl Armstrong
s/ BENTON L. BECKER Director April 19, 2002 - ------------------------ Benton L. Becker
s/ BILL L. HARBERT Director April 19, 2002 - ------------------------ Bill L. Harbert
s/ ROBERT D. HATCHER, JR. Director April 18, 2002 - ------------------------ Robert D. Hatcher, Jr.
s/ CHARLES M. STIVERS Director April 19, 2002 - ------------------------ Charles M. Stivers
s/ HAROLD G. MORRIS, JR. President April 19, 2002 - ------------------------ Harold G. Morris, Jr.
s/ MARK A. RUTH Principal Financial April 19, 2002 - ------------------------ and Accounting Officer Mark A. Ruth
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
TENGASCO, INC. AND SUBSIDIARIES
- --------------------------------------------------------------------------------
CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
TENGASCO, INC. AND SUBSIDIARIES
CONTENTS
- --------------------------------------------------------------------------------
INDEPENDENT AUDITORS' REPORT
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance sheets -5
Consolidated Statements of loss
Consolidated Statements of stockholders' equity -8
Consolidated Statements of cash flows -10
Notes to consolidated financial statements -37
Independent Auditors' Report
Board of Directors Tengasco, Inc. and Subsidiaries Knoxville, Tennessee
We have audited the accompanying consolidated balance sheets of Tengasco, Inc. and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of loss, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall 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 financial position of Tengasco, Inc. and Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has an accumulated deficit of $24,115,382. Additionally, on April 5, 2002, the Company's lender reduced its borrowing base under its revolving line of credit agreement by $6,000,000, which amount has become immediately due and payable resulting in a significant working capital deficiency. Such matters raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Atlanta, Georgia March 12, 2002, except for Note 2, which is as of April 12, 2002
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF LOSS
- --------------------------------------------------------------------------------
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
- --------------------------------------------------------------------------------
TREASURY STOCK ---------------------------- SHARES AMOUNT TOTAL -------------- ------------- -------------- -- $ -- $ 6,845,090
(2,671,923)
-- -- 509,000
-- -- 10,000
-- -- 162,500 ------------
-- -- 2,772,498
-- 42,000
-- -- (119,347)
-- -- (95,888) ---------- ------- ------------
-- -- 7,453,930
-- -- (1,541,884)
-- -- 449,994
-- -- 180,013
-- -- 50,000
-- -- 242,000
-- -- 4,245,708
-- -- 41,998
-- -- (257,557) ---------- ------- ------------
$ -- $ -- $ 10,864,202
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
- --------------------------------------------------------------------------------
TREASURY STOCK ------------------ SHARES AMOUNT TOTAL =======================================
-- $ -- $ 10,864,202
-- -- (2,262,787)
-- -- --
-- -- 523,250
-- -- 2,341,000
-- -- 71,001
-- -- 70,000
-- -- 3,899,998
-- -- 22,253
14,500 (145,887) (145,887)
-- -- (391,183) - --------- ------- ------------
14,500 $(145,887) $ 14,991,847 =======================================
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1. SUMMARY OF ORGANIZATION SIGNIFICANT ACCOUNTING Tengasco, Inc. (the "Company"), a publicly held POLICIES corporation, was organized under the laws of the State of Utah on April 18, 1916, as Gold Deposit Mining and Milling Company. The Company subsequently changed its name to Onasco Companies, Inc.
Effective May 2, 1995, Industrial Resources Corporation, a Kentucky corporation ("IRC"), acquired voting control of the Company in exchange for approximately 60% of the assets of IRC. Accordingly, the assets acquired, which included certain oil and gas leases, equipment, marketable securities and vehicles, were recorded at IRC's historical cost. The transaction was accomplished through the Company's issuance of 4,000,000 shares of its common stock and a $450,000, 8% promissory note payable to IRC. The promissory note was converted into 83,799 shares of Tengasco, Inc. common stock in December 1995.
The Company changed its domicile from the State of Utah to the State of Tennessee on May 5, 1995 and its name was changed from "Onasco Companies, Inc." to "Tengasco, Inc."
The Company's principal business consists of oil and gas exploration, production and related property management in the Appalachian region of eastern Tennessee and in the state of Kansas. The Company's corporate offices are in Knoxville, Tennessee. The Company operates as one reportable business segment, based on the similarity of activities.
During 1996, the Company formed Tengasco Pipeline Corporation ("TPC"), a wholly-owned subsidiary, to manage the construction and operation of a 65-mile gas pipeline as well as other pipelines planned for the future. During 2001, TPC began transmission of natural gas through its pipeline to customers of Tengasco.
BASIS OF PRESENTATION
The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation and Tennessee Land and Mineral, Inc. All significant intercompany balances and transactions have been eliminated.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
USE OF ESTIMATES
The accompanying financial statements are prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The actual results could differ from those estimates.
REVENUE RECOGNITION
The Company recognizes revenues at the time of exchange of goods and services.
CASH AND CASH EQUIVALENTS
The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.
RESTRICTED CASH
At December 31, 2001 the Company had cash in escrow related to an ongoing pricing dispute with King Pipeline Corporation. The Company is disputing certain amounts billed by King Pipeline Corporation to the Company for construction of the pipeline. This cash will be restricted until a judgment has been reached in this case.
INVESTMENT SECURITIES
Investment securities available for sale are reported at fair value, with unrealized gains and losses, when material, reported as a separate component of stockholders' equity, net of the related tax effect.
INVENTORY
Inventory consists primarily of crude oil in tanks and is carried at market value.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals and the costs of drilling, completing and equipping oil and gas wells. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs.
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company's proved gas reserves were estimated by Columbia Engineering, independent petroleum engineers, for the Kansas properties, and by Coburn Petroleum Engineering for the Tennessee properties in 1999. These reserves were estimated by Ryder Scott Company, Petroleum Consultants in 2000 and 2001.
The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling writedown was recorded in 2001, 2000 or 1999.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
PIPELINE FACILITIES
Pipeline facilities under construction consist of direct and indirect construction costs, capitalized interest and capitalized overhead. Phase I of the pipeline was completed during 1999. Phase II of the pipeline was completed on March 8, 2001. Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years, beginning at the time it was placed in service. Accordingly, no depreciation expense has been recorded for 2000 and 1999 relating to pipeline facilities. During 2001, depreciation expense of $220,371 was recorded relating to the pipeline.
OTHER PROPERTY AND EQUIPMENT
Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from five to ten years.
IMPAIRMENT OF LONG-LIVED ASSETS AND LONG-LIVED ASSETS TO BE DISPOSED OF
Management believes that carrying amounts of all of the Company's long-lived assets will be fully recovered over the course of the Company's normal future operations. Accordingly, the accompanying financial statements reflect no charges or allowances for impairment.
DERIVATIVES
The Company uses collar contracts to partially mitigate the effects of fluctuations in the price of crude oil and natural gas. These contracts are marked to market with current recognition of gains and losses on such positions to be included in Other Income since the Company's positions are not considered hedges for financial reporting purposes. The Company's accounting for collar contracts may have the effect of increasing earnings volatility in any particular period. Derivative activities entered into on December 28, 2001 were not material to the Company's financial position or results of operations as of and for the year ended December 3,1 2001. The Company does not hold or issue derivative instruments for speculative purposes.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
INCOME TAXES
The Company accounts for income taxes using the "liability method." Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carryforwards. Management evaluates the likelihood of realization of such assets at year end reserving any such amounts not likely to be recovered in future periods.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At times, such cash in banks is in excess of the FDIC insurance limit. At December 31, 2001, the Company had deposits with two financial institutions in amounts which exceeded the federally insured limit by approximately $275,000 and $100,000.
The Company's primary business activities include oil and gas sales to several customers in the states of Tennessee and Kansas. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry.
The Company has entered into a contract to supply a chemical manufacturer with natural gas from the Swan Creek field and through the pipeline. This customer will be the Company's primary customer of natural gas sales. Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Company's projected results of operations.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
LOSS PER COMMON SHARE
Basic loss per share is computed by dividing loss available to common shareholders by the weighted average number of shares outstanding during each year. Shares issued during the year are weighted for the portion of the year that they were outstanding. Diluted loss per share is not calculated since it is anti-dilutive. Basic and diluted loss per share are based upon 10,235,253 shares for the year ended December 31, 2001, 9,253,622 shares for the year ended December 31, 2000 and 8,557,395 shares for the year ended December 31, 1999. There were 943,005, 1,000,763 and 732,967 potential weighted average common shares outstanding during 2001, 2000 and 1999 related to common stock options and warrants. These shares were not included in the computation of the diluted loss per share amount because the Company was in a net loss position and, thus, any potential common shares were anti-dilutive. All share and per share amounts have been adjusted to reflect the 5% stock dividend. See Note 10.
FAIR VALUES OF FINANCIAL INSTRUMENTS
Fair values of cash and cash equivalents, investments and short-term debt approximate cost due to the short period of time to maturity. Fair values of long-term debt are based on quoted market prices or pricing models using current market rates, which approximate carrying values.
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," effective January 1, 2001. SFAS No. 133 (as amended by SFAS 137 and SFAS 138) requires a company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a fair value hedge, changes in the fair value of the hedged assets, liabilities or firm commitments are recognized through earnings. If the derivative is a cash flow hedge the effective portion of changes in the fair value of the derivative are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings. The adoption of SFAS No. 133, as amended, did not have a material impact on the Company's consolidated financial statements.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In July 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard (SFAS) No. 141, "Business Combinations" and SFAS No.142, "Goodwill and Other Intangible Assets". SFAS No. 141 addresses the initial recognition and measurement of goodwill and other intangible assets acquired in a business combination and SFAS No. 142 addresses the initial recognition and measurement of intangible assets acquired outside of a business combination whether acquired individually or with a group of other assets. These standards require all future business combinations to be accounted for using the purchase method of accounting. Goodwill will no longer be amortized but instead will be subject to impairment tests at least annually. The Company would have been required to adopt SFAS No. 141 on July 1, 2001, and to adopt SFAS 142 on a prospective basis as of January 1, 2002. The Company has not effected a business combination and carries no goodwill on its balance sheet; accordingly, the adoption of these standards is not expected to have an effect on the Company's financial position or results of operations.
In June 2001, the Financial Accounting Standards Board approved the issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS 143 establishes accounting standards for the recognition and measurement of legal obligations associated with the retirement of tangible long-lived assets and requires recognition of a liability for an asset retirement obligation in the period in which it is incurred. The provisions of this statement are effective for financial statements issued for fiscal years beginning after June 15, 2002. The adoption of this statement is not expected to have a material impact on the Company's financial position or results of operations.
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and expands on the guidance provided by SFAS No. 121 with respect to cash flow estimations. SFAS No. 144 becomes effective for the Company's fiscal year beginning January 1, 2002. There will be no current impact of adoption on its financial position or results of operations.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform with current year presentation.
2. GOING CONCERN The accompanying consolidated financial statements UNCERTAINTY have been prepared in conformity with accounting principles generally accepted in the United States of America, which contemplate continuation of the Company as a going concern which assumes realization of assets and the satisfaction of liabilities in the normal course of business. The Company continues to be in the early stages of its oil and gas related operating history as it endeavors to expand its operations through the continuation of its drilling program in the Tennessee Swan Creek Field. Accordingly, the Company has incurred continuous losses through these operating stages and has an accumulated deficit of $24,115,382 and a working capital deficit of $6,326,204 as of December 31, 2001. On April 5, 2002, the Company was informed by its primary lender that $6,000,000 of its outstanding credit facility was due and payable within 30 days, as provided for in the Credit Agreement (see Note 7). These circumstances raise substantial doubt about the Company's ability to continue as a going concern.
The Company has disputed its obligation to make this payment and is attempting to resolve the dispute or to obtain alternative refinancing arrangements to repay this current obligation. There can be no assurance that the Company will be successful in its plans to obtain the financing necessary to satisfy their current obligations.
3. RELATED PARTY During 2001, the Company repaid all principal and TRANSACTIONS interest due to related parties, using the proceeds from the line of credit with Bank One. Interest incurred to related parties was $546,026 for the year ended December 31, 2001.
During 2001, the Company converted debt of $200,000 payable to a director into 42,017 shares of common stock.
No consulting fees or commissions on equity transactions were paid to related parties in 2001.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
During 2000, the Company acquired debt financing in the amount of $3,850,000 from two members of the board of directors, one affiliate, and two shareholders in order to complete construction of its pipeline from Swan Creek to Kingsport (see Note 5). The directors will also receive a throughput fee once production begins, and will continue to receive such fees until the debt is repaid. The throughput fee is 10 cents per MMBtu delivered through the pipeline in proportion to the director's proportion of total debt. The volume delivered shall be calculated on a monthly basis. The throughput fee was $82,373 in 2001. No throughput fees were incurred in 2000 or 1999 as the pipeline was not yet operational.
During 2000, the Company incurred debt to a major officer/stockholder in the amount of $995,000 in order to purchase a drilling rig from that officer/stockholder (see Note 7).
During 2000, the Company paid approximately $270,000 in consulting fees and commissions on equity transactions to a member of the Board of Directors.
Interest expense incurred to related parties during 2000 was $135,435.
In December 1999, the Company sold for aggregate consideration of $625,000 a 25% working interest in two wells and a 50% working interest in a third well, located in the Swan Creek Field, to a related party company affiliated with a member of the Board of Directors.
During 1999, the Company converted $250,000 of debt together with accrued interest thereon payable to a major officer/stockholder of the Company into 54,000 shares of common stock. In addition, the Company converted $163,800 of non-interest bearing accounts payable to this officer/stockholder into 16,800 shares of common stock.
During 1999, the Company converted $22,000 of debt payable to a company owned by a member of the Board of Directors for consulting services into 5,625 shares of common stock.
During 1999, the Company paid approximately $218,000 in consulting fees and commissions on equity transactions to a member of the Board of Directors.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
4. OIL AND GAS The following table sets forth information PROPERTIES concerning the Company's oil and gas properties:
During the years ended December 31, 2001, 2000 and 1999, the Company recorded depletion expense of $1,342,000, $197,000 and $92,000, respectively. Significant increases in depletion expense were incurred during 2001 as a result of decreased oil and gas estimated proved reserves.
5. PIPELINE FACILITIES In 1996, the Company began construction of a 65-mile gas pipeline (1) connecting the Swan Creek development project to a gas purchaser and (2) enabling the Company to develop gas distribution business opportunities in the future. Phase I, a 30-mile portion of the pipeline, was completed in 1998. Phase II of the pipeline was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company used the half-life convention to calculate depreciation on the pipeline in 2001 and recorded approximately $220,000 in depreciation expense.
In January 1997, the Company entered into an agreement with the Tennessee Valley Authority ("TVA") whereby the TVA allows the Company to bury the pipeline within the TVA's transmission line rights-of-way. In return for this right, the Company paid $35,000 and agreed to annual payments of approximately $6,200 for 20 years. This agreement expires in 2017 at which time the parties may renew the agreement for another 20 year term in consideration of similar inflation-adjusted payment terms.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
6. OTHER PROPERTY Other property and equipment consisted of the AND EQUIPMENT following:
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
7. LONG TERM DEBT Long-term debt to unrelated entities consisted of the following:
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Long-term debt to related parties consisted of the following:
All long-term debt to related parties was repaid in November 2001.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The aggregate maturities of long term debt as of December 31, 2001, are as follows:
8. COMMITMENTS The Company is a party to lawsuits in the ordinary AND CONTINGENCIES course of its business. While the damages sought in some of these actions are material, the Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have a material adverse effect in the aggregate.
In the ordinary course of business the Company has entered into various equipment and office leases which have terms ranging from one to five years. Approximate future minimum lease payments to be made under noncancellable operating leases are as follows:
Office rent expense was approximately $91,228, $86,120 and $52,590 for each of the three years ended December 31, 2001, respectively.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
9. CONVERTIBLE In December 1998, the Company's Board of Directors REDEEMABLE authorized the issuance of 100,000 shares of PREFERRED STOCK Series A Convertible Redeemable Preferred Stock ("Series A Preferred Stock"). In December 1999, the Company's Board of Directors authorized the issuance of 100,000 shares of Series B Convertible Redeemable Preferred Stock ("Series B Preferred Stock").
Shares of both Series A and B of Preferred Stock are or will be immediately convertible into shares of Common Stock. Each $100 liquidation preference share of preferred stock is convertible at a rate of $7.00 for the Series A per share of common stock. For the Series B, the conversion rate is the average market price of the Company's common stock for 30 days before the sale of the Series B preferred stock with a minimum conversion price of $9.00 per share. The conversion rate is subject to downward adjustment if the Company subsequently issues shares of common stock for consideration less than $7.00 and $9.00 for the Series A and B, respectively, per share. The conversion prices will be adjusted prospectively for stock dividends and splits.
In 2000, the Company issued 1,000 shares of Series A Preferred Stock for $1,000,000, which netted the Company approximately $960,000 after commissions. In the same year, the Company issued 1,000 shares of Series B Preferred Stock for $1,000,000. No commissions were paid on the Series B Preferred Stock. In April 2000, one holder converted 5,000 shares of Series A Preferred Stock into Common Stock. No additional consideration was given to the Company for this conversion.
In conjunction with the issuances of the Series B Preferred Stock described above, the Company granted the purchasers detachable stock warrants which enable the holders to obtain up to 11,111 shares of the Company's common stock at an exercise price of $9 per share.
In 2001, the Company issued 1,755 shares of Series B Preferred Stock for $1,755,000, which netted the Company approximately $1,591,000 after commissions. In June 2001, one holder converted 710 shares of Series A Preferred Stock into Common Stock. No additional consideration was given to the Company for this conversion.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The holders of both the Series A and Series B Preferred Stock are entitled to a cumulative dividend of 8% per quarter. However, the payment of the dividends on the Series B Preferred Stock is subordinate to that of the Series A Preferred Stock. In the event that the Company does not make any two of six consecutive quarterly dividend payments, the holders of the Series A Preferred Stock may appoint those directors which would constitute of majority of the Board of Directors. In such a scenario, the holders of the Preferred Shares would be entitled to elect a majority of the Board of Directors until all accrued and unpaid dividends have been paid.
The Company may redeem both of the Series A and B Preferred Shares upon payment of $100 per share plus any accrued and unpaid dividends. Further, with respect to the Series A Preferred Stock, commencing on October 1, 2003 and at each quarterly date thereafter while the Series A Preferred Stock is outstanding, the Company is required to redeem one-twentieth of the maximum number of Series A Preferred Stock outstanding. With respect to the Series B Preferred Stock, on the fifth anniversary after issuance, the Company is required to redeem all outstanding Series B Preferred Stock.
10. STOCK DIVIDEND On August 1, 2001, the Company paid a 5% stock dividend distributable on October 1, 2001 to shareholders of record of the Company's common stock on September 4, 2001. Based on the number of common shares outstanding on the record date, the Company issued 498,016 new shares. All references in the accompanying financial statements to the number of common shares and per share amounts are based on the increased number of shares giving retroactive effect to the stock dividend.
11. STOCK OPTIONS In October 2000, the Company approved a Stock Incentive Plan. The Plan is effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to Employees under the plan shall not exceed 1,000,000. Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Nonqualified Stock Option Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the Fair Market Value of such shares on the date of grant. Furthermore, an employee in the plan may not, immediately prior
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
to the grant of an Incentive Stock Option hereunder, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such and Employee is at least 110% of the Fair Market Value of the Company's stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.
Stock option activity in 2001, 2000 and 1999 is summarized below:
The share information disclosed above has been adjusted to reflect the 5% stock dividend declared during 2001. See Note 10.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The following table summarizes information about stock options outstanding at December 31, 2001:
The weighted average fair value of options granted during 2001, 2000 and 1999 is $3.62, $3.41 and $2.88 respectively, calculated using the Black-Scholes Option-Pricing model.
The amount of compensation expense related to stock options included in general and administrative costs in the accompanying consolidated statements of loss was approximately $162,500 for the year ended December 31, 1999. No compensation expense related to stock options was incurred in 2001 or 2000. The Company issued 70,715 options to non-employees and non-directors in 2000. The expense of $242,000 for these options has been included in professional fees expense because the options were issued to providers of such services. The expense was calculated using a fair market value of the options based on the Black-Scholes option-pricing model assumptions discussed below.
Statement of Financial Accounting Standards No. 123, ("SFAS 123"), "Accounting for Stock-Based Compensation" was implemented in January 1996. As permitted by SFAS 123, the Company has continued to account for stock compensation to employees by applying the provisions of Accounting Principles Board Opinion No. 25. If the accounting provisions of SFAS 123 had been adopted, net loss and loss per share would have been as follows:
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
For employees, the fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2001, 2000 and 1999: Expected volatility of 50% for 2001 and 2000 and 106% for 1999; a risk free interest rate of 3.67% in 2001, 5.86% in 2000 and 6.17% in 1999; and an expected option life of 3 years for 2001 and 2000 and 1.1 year in 1999.
12. INCOME TAXES The Company had no taxable income during the years ended December 31, 2001, 2000 or 1999.
A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of loss is as follows:
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The components of the net deferred tax assets are as follows:
The Company recorded a valuation allowance at December 31, 2001 and 2000 equal to the excess of deferred tax assets over deferred tax liabilities as management is unable to determine that these tax benefits are more likely than not to be realized.
As of December 31, 2001, the Company had net operating loss carryforwards of approximately $15,062,000, which will expire between 2010 and 2021, if not utilized.
Additionally, at December 31, 2001, the Company had capital loss carryforwards of approximately $81,000 which will expire, if not offset against capital gains, in 2002.
13. SUPPLEMENTAL CASH The Company paid approximately $853,500, $544,000 FLOW INFORMATION and $479,000 for interest in 2001, 2000 and 1999, respectively. The Company capitalized approximately $148,000 and $128,000 of this amount in 2001 and 2000, respectively. The Company paid no income taxes in 2001, 2000 and 1999.
In 1999, the Company issued 54,000 shares of common stock to convert a note payable to an officer plus accrued interest thereon in the approximate amount of $270,000, which approximated the fair value of the shares.
In 2001, 2000 and 1999, the Company issued 11,950, 5,376 and 9,768 shares of common stock as consideration for approximately $92,000, $42,000 and $42,000, respectively, of services and charitable contributions which approximated the fair value of the common stock.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In 1999, the lender of the note payable with an original balance of $1,500,000 sold $75,000 of this note to other holders. These holders then converted the notes into common stock at the rate of $6.25 per share. In 2000, the lender converted approximately $450,000 of the outstanding debt into common stock under the same agreement.
14. QUARTERLY DATA AND The following table sets forth, for the fiscal SHARE INFORMATION periods indicated, selected consolidated financial (UNAUDITED) data and information regarding the market price per share of the Company's common stock. The prices represent the reported high and low closing sale prices.
Third quarter 2001 results reflect the effect on depletion expense that resulted from a decrease in reserve estimates provided in a study performed by Ryder Scott and issued August 10, 2001. The amount recorded during this quarter was $562,000 higher than the quarterly estimates made by management during the first three quarters as a result of a change in estimate arising from new information provided in the Ryder Scott Report. Amounts disclosed above differ from those filed with the SEC during the third quarter of 2001 as a result of an error in recording this change in estimate to depletion at the time of
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
the filing. Management intends to amend the September 30, 2001 SEC Form 10-Q filing.
15. SUPPLEMENTAL OIL AND Information with respect to the Company's oil and GAS INFORMATION gas producing activities is presented in the following tables. Estimates of reserve quantities, as well as future production and discounted cash flows before income taxes, were determined by Ryder Scott Company, L.P. as of December 31, 2001 and 2000 and by Coburn Petroleum Engineering and Columbia Engineering, independent petroleum engineers, as of December 31, 1999.
OIL AND GAS RELATED COSTS
The following table sets forth information concerning costs related to the Company's oil and gas property acquisition, exploration and development activities in the United States during the years ended December 31, 2001, 2000 and 1999:
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the Company's results of operations from oil and gas producing activities for the years ended:
In the presentation above, no deduction has been made for indirect
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company's tax loss carryforwards.
OIL AND GAS RESERVES (UNAUDITED)
The following table sets forth the Company's net proved oil and gas reserves at December 31, 2001 and 2000 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The reserve information indicated below requires substantial judgment on the part of the reserve engineers, resulting in estimates which are not subject to precise determination. Accordingly, it is expected that the estimates of reserves will change as future production and development information becomes available and that revisions in these estimates could be significant. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (MCF) in the case of gas.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Of the Company's total proved reserves as of December 31, 2001 and 2000 and 1999, approximately 36%, 21% and 13%, respectively, were classified as proved developed producing, 26%, 34% and 35%, respectively, were classified as proved developed non-producing and 37%, 45% and 52%, respectively, were classified as proved undeveloped. All of the Company's reserves are located in the continental United States.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The standardized measure of discounted future net cash flows from the Company's proved oil and gas reserves is presented in the following table:
The following table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves during 2001 and 2000:
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2001, 2000 and 1999 were $17.03, $25.62 and $23.01 per barrel of oil and $2.33, $9.66 and $2.38 per MCF of gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax.
The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.