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 services. The Company utilizes seismic technology to improve the recovery of reserves.
The Company's activities in the oil and gas business commenced in May
with the acquisition of oil and gas leases in Hancock, Claiborne, Knox, Jefferson and Union counties in Tennessee. The Company's current lease position in these areas in Tennessee is approximately 28,338 acres.
To date, the Company has drilled primarily on a portion of its Tennessee leases known as the Swan Creek Field in Hancock County focused within what is known as the Knox formation, one of the geologic formations in that field. During 2003, the Company produced an average of approximately 1.075 million cubic feet of natural gas per day and 2,024 barrels of oil per month from 25 producing gas wells and six producing oil wells in the Swan Creek Field.
In 2001, the Company's wholly-owned subsidiary, Tengasco Pipeline Corporation ("TPC") completed a 65-mile intrastate pipeline from the Swan Creek Field to Kingsport, Tennessee. Until the Company's pipeline was completed, the gas wells that had been drilled in the Swan Creek Field could not be placed into actual production and the gas transported and sold to the Company's industrial customers in Kingsport. The Company initially believed that the production of natural gas from the Swan Creek Field would be significantly higher than the actually experienced production. The reasons for the lower production volumes include initial production problems caused by naturally occurring fluids entering the well bore, slower than anticipated production of the wells due to underground reservoir characteristics that became apparent only when the wells were placed into actual production, and the inability of the Company to drill additional wells due to shortage of available capital. The Company has taken steps to minimize fluid problems in existing wells by mechanical means and to avoid them in future wells by drilling and completion techniques. Management believes, however, that the only way to increase production volumes of gas from this field is to drill additional wells to drain the underground reservoirs of the full reserves of gas, and the Company's ability to do so is dependent upon raising additional capital for drilling. There can be no assurances that the Company will be able to resolve the difficulties currently preventing it from obtaining capital for drilling additional wells and increasing production volumes of natural gas from the Swan Creek Field.
In 1998, 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 that acquisition were 273 wells, including 208 working wells, of which 149 were producing oil wells and 59 were producing gas wells, a related 50-mile pipeline and gathering system, three compressors and 11 vehicles. The total purchase price of these assets was approximately $5.5 million. During 2003, the Kansas Properties produced an average of approximately 648 MMcf of natural gas per day and 10,246 barrels of oil per month. Gross revenues from the Kansas Properties during 2003 were $3,721,601.
HISTORY OF THE COMPANY
The Company was initially organized under the laws of the State of Utah in 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. In 1972, the Company conveyed to an unaffiliated entity substantially all of its assets and 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.
In 1995, the Company acquired certain oil and gas leases, equipment, securities and vehicles owned by Industrial Resources Corporation, a Kentucky corporation, changed its name from Onasco Companies, Inc. to Tengasco, Inc., and changed the domicile of the Company from the State of Utah to the State of Tennessee by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose.
During 1996, the Company formed TPC 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, during the late 1970's and early 1980's acquired approximately 50,500 acres of oil and gas leases in the Eastern Overthrust in the Appalachian Basin, including the area now referred to as the Swan Creek Field. In 1982, Amoco successfully drilled two 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 apparent volume of deliverability of natural gas. In the mid-1980's, however, development of this Field was cost prohibitive due to a substantial decline in worldwide oil and gas prices which was further exacerbated by the high cost of constructing a necessary 23-mile pipeline across three rugged mountain ranges and crossing the environmentally protected Clinch River from Sneedville, Tennessee to deliver gas from the Swan Creek Field to the closest market in Rogersville, Tennessee. In 1987, Amoco farmed out its leases to Eastern American Energy Company which held the leases until July 1995. In July 1995, the Company commenced a legal action, under laws passed by the Tennessee legislature, as to its right to lease Amoco's prior acreage. In July 1995 pursuant to such action, the Company acquired the Swan Creek leases. These leases provide for a landowner royalty of 12.5%.
A. SWAN CREEK PIPELINE FACILITIES
In July 1998, the Company completed Phase I of its pipeline from the Swan Creek Field, a 30-mile pipeline made of six- and eight-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.
In April 2000, construction commenced on Phase II of the Company's pipeline. This was an additional 35 miles of eight- and 12-inch pipe laid at a cost 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 Chemical Company's chemical plant. The pipeline system was completed in March 2001. The overall cost was approximately $16.4 million at December 31, 2003 and the pipeline extends 65 miles from the Company's Swan Creek Field to Kingsport, Tennessee.
B. SWAN CREEK CONTRACTUAL ARRANGEMENTS
In November 1999, the Company entered into an agreement with Eastman Chemical Company ("Eastman") that provides that Eastman would purchase daily from the Swan Creek Field at 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 had 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 would have allowed the gas to be used in certain processes in the Eastman plant requiring low levels of non- hydrocarbons. If the Company elected to perform this option by installing additional facilities, the minimum daily amount of gas to be purchased by Eastman from the Company would 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.
In March 2000, the Company signed an amendment to the agreement with Eastman permitting the Company a further option with respect to the allowable level of non-hydrocarbons in the delivered gas from the Swan Creek Field. 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 agreed 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, to the Company's knowledge, none of the gas sold by the Company to Eastman exceeds the allowable level of non-hydrocarbons permitted under the agreement and no such gas requires treatment.
Under the agreement as amended in March 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. The
agreement with Eastman is for an initial 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 commenced in March 2001.
In January 2000, TPC, signed a franchise agreement to install and operate new natural gas utility services for residential, commercial and industrial users in Hancock County, Tennessee for the Powell Valley Utility District (the "District"). The District had no existing natural gas facilities and the system to be installed by TPC was initially intended to extend to schools and small customers and gradually be expanded over time to serve as many of the 6,900 residents of the County as is economically feasible. TPC purchases gas from the Company on behalf of the District, which gas is to 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 by the Company for an additional ten years, TPC will receive 95% of the gross proceeds of the sale of gas for its services under the agreement. In June 2000, TPC began installation of the necessary facilities to begin to serve 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 in December 2000. The cost of construction of these facilities was approximately $300,000. Upon enactment of initial rate schedules by the District, initial sales began in January 2001 to a small number of residential and small commercial customers.
In March 2002, the Company began delivering gas to its first commercial customer, Kiefer Built, Inc., an Iowa-based manufacturer of livestock and industrial trailers, in a new industrial park in Sneedville. Although there can be no assurance, the Company hopes to be able to supply gas to other District customers who may move into that industrial park. At this time, however, 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, the Company is not able to predict when such sales may begin, if at all, or what the overall volumes of gas sold may be. Due to the small number of existing customers and relatively high operating costs, the Company intends to either expand the operation of this system so as to increase revenues or to sell these assets to neighboring utilities or the City of Sneedville. In the event of such a sale, the Company could still sell gas to the District.
In March 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 may be between 1.8 million and five million cubic feet, and volume could, although there can be no assurance, increase 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 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 is expected to serve as a location for additional commercial and industrial customers. Although there can be no assurance, the Company's presence at the Holston Business and Technology Park is expected to position it to provide gas service to those customers and the Company understands that its presence is considered by BAE to be a favorable factor in the development of the Park.
C. SWAN CREEK PRODUCTION AND DEVELOPMENT
The Company began delivering gas through its pipeline to BAE in April 2001 and to Eastman in May 2001. Daily production in June 2001 averaged 4,936.2 Mcf and in July 2001 daily production averages increased to 5,497 Mcf per day. Although the Company's gas production in mid-2001 was at anticipated levels, the Company was unable to maintain those production levels for the remainder of 2001 and since then. This was due primarily to three problems:
o initial fluid problems in some wells;
o natural and expected production declines from the type of reservoir that exists in the Swan Creek field; and
o the Company's inability to offset expected natural declines in production by drilling new wells because of inadequate capital.
As to the first of these problems, the Company experienced the in-flow of substantially more fluids in the existing wells than had been expected when they were first brought into continuous production in 2001. These fluids entered the wells from the boreholes. The fluids obstructed and significantly reduced the flow of gas from the existing wells in the Swan Creek Field and required substantial additional work and repairs to increase the production from existing wells. First, a drip tank system was installed to eliminate the fluids in the pipeline. Next, mechanical devices were installed in many of the existing wells to reduce the fluid problems. Many of the existing wells had to be shut down while the repairs were made. Gas lifts have been installed in 15 of the Company's existing wells and act as mechanisms to remove the fluids and stabilize erratic behavior, such as large swings in individual well production. These measures have had only limited success in increasing production from existing wells. It is expected that techniques used in addressing these fluid problems will be applied in future wells in the Swan Creek Field and the Company anticipates, although there can be no assurance, that this will minimize or prevent these problems.
As to the second problem, the Company experienced an expected and what it believes is a normal decline in initial production from existing wells in the newly-producing Swan Creek Field. The Company believes that all types of gas wells experience some type of decline in the course of initial production. These declines were expected and do not diminish either the shut-in pressure or the Company's actual reserves in the Swan Creek Field. The declines, however, suggest the production rates from some of the Company's smaller wells will continue to be slower, which may result in such wells lasting longer than it was originally expected.
As to the third problem, the declines in production have not been addressed and replaced by additional drilling as the Company had planned. The Company believes that in order for overall field production to remain steady or grow in a field such as the Swan Creek Field, new wells must be brought online to offset the normal production declines in wells as described above. The Company anticipates, although there can be no assurances, that any new wells it drills in the Swan Creek Field would experience a similar harmonic (i.e. a relatively steep initial decline curve followed by longer periods of relatively flat or stable production) decline as a normal function. Consequently, continuous drilling is important to maintaining or increasing initial levels of production. Only two gas wells were added by the Company in 2002 and no new wells were drilled in the Swan Creek Field in 2003 due to the Company's inability to raise capital to pay for the costs of such drilling caused by the Company's dispute with its primary lender, Bank One, N.A. See below, "Item 3 - Legal Proceedings" and "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operation - Liuidity and Capital Resources". The Company anticipates that the natural decline of production from existing wells is now predictable in the Swan Creek Field, that the total volume of its reserves remains largely intact, and that these reserves can be extracted through both existing wells and by drilling of additional wells, subject to the availability of requisite funding. There can be no assurance that the Company will have or be able to further raise sufficient capital to fund its proposed drilling program to successfully increase production from the Swan Creek Field.
Due to natural and expected declines that continue to occur in ongoing production from any oil and gas well, some additional declines are expected to occur in production from the Company's existing wells in the Swan Creek Field. Although there can be no assurance, the Company expects these natural declines to be less than the decline experienced to date, and that ongoing production from existing wells will tend to level off. This expectation is based on two factors:
o first, repairs have been performed on many of the existing wells, and
o second, the natural production decline from any well is normally greatest during the initial producing periods, which initial periods have largely elapsed.
Natural gas production from the Swan Creek Field during 2003 averaged 1.075 million cubic feet per day compared to 1.966 million cubic feet per day in 2002. This production history reflects a combination of natural and expected decline from initial production from
existing wells. During 2003, no wells were added to offset the natural and expected declines in production from existing wells.
During 2003, the Company had 25 producing gas wells and 6 producing oil wells in the Swan Creek Field. Miller Petroleum, Inc. and others had a participating interest in 7 of these wells. See, "Item 2
ITEM 2. PROPERTIES
PROPERTY LOCATION, FACILITIES, SIZE AND NATURE OF OWNERSHIP
SWAN CREEK FIELD
The Company's Swan Creek Leases are on approximately 28,338 acres in Hancock, Claiborne, Knox, Jefferson, Morgan and Union Counties in Tennessee. The initial terms of these leases vary from one to five years. Some of them will terminate unless the Company has commenced drilling. In 2002, the Company reduced the acreage comprising the Swan Creek Field from approximately 50,500 acres to 41,088 acres. In 2003, the acreage in the Swan Creek Field was again further reduced to the present 28,338 acres. These reductions in acreage were a result of the Company having a better understanding of the geological and geophysical makeup of the Swan Creek Field. Management believes the acreage eliminated from the Field does not have the potential to produce commercial quantities of oil or gas and that the reduction of this acreage does not affect the reserves of the Swan Creek Field. Further, the elimination of the leases for this acreage will result in beneficial cost savings to the Company.
Morita Properties, Inc., an affiliate of Shigemi Morita, a former Director of the Company, currently has a 25% overriding royalty in nine of the Company's existing wells, and a 50% overriding royalty and 6% overriding royalty, respectively, in two of the Company's other existing wells. All of these wells are located in the Swan Creek Field and all but two 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 Stephen 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 her proportionate share of drilling costs.
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, as defined, are to be 81.25% to Miller. The Company's subsidiary TPC 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.
Other working interest owners in oil and gas wells in which the Company has working interests 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 were to agree to market gas for working interest owners to customers other than the Company's customers, the Company would 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 production may be correspondingly reduced. If the working interest owners make their own arrangements to market their natural gas to other end users along the Company's pipeline such gas would be transported by TPC at published tariff rates. The current published tariff rate is for firm transportation at a demand or "reservation" 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.
KANSAS PROPERTIES
The Kansas Properties contain 138 leases totaling 32,158 acres in the vicinity of Hays, Kansas. The original terms on these leases were from 1 to 10 years and in most cases have expired. Most of these leases, however, 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%.
Although the Company does not pay taxes on its Swan Creek leases, it pays ad valorem taxes on its Kansas Properties. 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 rental of $4,705.83 per month and an office in Hays, Kansas at a rental of $500 per month. During 2002 and the first quarter of 2003, the Company closed a field office in Sneedville, Tennessee and an office in New York City it had previously leased at an aggregate rental of $3,100 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, and performed these services at their standard rates. The net reserve values used hereafter were obtained from a reserve report dated February 10, 2004 (the "Report") prepared by Ryder Scott as of December 31, 2003.
The Report indicates the Company's "TOTAL PROVEN ALL CATEGORIES" reserves for the Company to be as follows: net production volumes of 1,371,134 barrels of oil and 14,344.703MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be $26,362,906. The Report indicates the "proven developed producing" reserved for the Company to be as follows: net production volumes of 1,059,038 barrels of oil and 5,167.832 MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be $12,224,953.
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 factors. 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 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.
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 SEC. The Company, however, has filed the information in the Report of the Company's reserves with the Energy Information Service of the Department of Energy in compliance with that agency's statutory function of surveying oil and gas reserves nationwide.
The term "Proved Oil and Gas Reserves" is defined in Rule 4-10(a)(2) of Regulation S-X promulgated by the SEC as follows:
2. Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil- water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
ii. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
iii. Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
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.
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(1) 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.
(2) The increase in cost of production in 2002 was a result of this being the first full year of production in the Swan Creek Field.
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 2003, due to the Company's inability to raise capital because of its dispute with Bank One the Company did not have sufficient funds to drill any new wells. During the past three fiscal years, the Company drilled one exploratory well in 2002 in Cocke County, Tennessee which did not result in finding commercial quantities of hydrocarbons. 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, 2001, 2002, and 2003 the number of gross and net development wells drilled by the Company. The dry hole set forth in the table below is the Cocke County well referred to above. 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.
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, 2003. 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 26 16 6 5 - -------------------------------------------------------------------------------- KANSAS 51 43 132 114 - --------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED OIL AND GAS ACREAGE
As of December 31, 2003, 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 1,280 742 28,338 24,839 - -------------------------------------------------------------------------------- KANSAS 9,666 8,080 22,711 18,995 - --------------------------------------------------------------------------------
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. TENGASCO, INC., TENGASCO LAND AND MINERAL CORPORATION AND TENGASCO PIPELINE CORPORATION V. BANK ONE, NA, Docket No. 2:02-CV-118 in the Eastern District of Tennessee, Northeastern Division at Greeneville.
On November 8, 2001, the Company signed a credit facility with Bank One, N.A. in Houston, Texas whereby Bank One extended to the Company a revolving line of credit of up to $35 million. The initial borrowing base under the facility was $10 million.
On April 5, 2002, the Company received a notice from Bank One stating that it had redetermined and reduced the then-existing borrowing base under the Credit Agreement by $6,000,000 to $3,101,777. Bank One demanded that the Company pay the $6,000,000 within thirty days. On May 2, 2002, the Company filed suit in federal court to restrain Bank One from taking any steps pursuant to its Credit Agreement to enforce its demand that the Company reduce its loan obligation or else be deemed in default and for damages resulting from the wrongful demand. It is the position of the Company that Bank One's demand that the Company reduce its loan from $9,101,777 to $3,101,777 within thirty days, coming only four months after the loan was made, in the absence of any change in the Company's production of oil and gas from the time the loan was closed or the condition of the Company's assets, without warning and prior to the receipt of a December 2002 reserve report, without any basis or explanation, is a violation of the Credit Agreement and an act of bad faith. The Company is seeking a jury trial and actual damages sustained by it as a result of the wrongful demand, in the amount of $51,000,000 plus punitive damages in the amount of $100 million.
On July 1, 2002, Bank One filed its answer and counterclaim, alleging that its actions were proper under the terms of the Credit Agreement, and in the counterclaim, seeking to recover all amounts it alleges to be owed under the Credit Agreement, including principal, accrued interest, expenses and attorney's fees in the approximate amount of $9 million. The Company has continued to pay the sum of $200,000 per month of principal due under the original terms of the Credit Agreement, plus interest, and has reduced the principal outstanding as of March 1, 2004 to approximately $4.5 million. Although the parties commenced discussions with regard to settlement of all outstanding issues, and continued such discussions for an extended period, no settlement has been concluded. A procedural schedule has been set by the Court leading toward a trial date of December 7, 2004 in the event a settlement is not concluded. Discovery has commenced according to the procedural schedule set by the Court.
2. PAUL MILLER V. M. E. RATLIFF AND TENGASCO, INC., Docket Number 3:02-CV-644 in the United States District Court for the Eastern District of Tennessee, Knoxville.
This action commenced in November 2002 seeks certification of a class action to recover on behalf of a class of all persons who purchased shares of the Company's common stock between August 1, 2001 and April 23, 2002, damages in an amount not specified which were allegedly caused by violations of the federal securities laws, specifically Rule 10b-5 issued under the Securities Exchange Act of 1934 as to the Company and Malcolm E. Ratliff, the Company's former Chief Executive Officer and a Director, and Section 20(a) the Securities Exchange Act of 1934 as to Mr. Ratliff. The complaint alleges that documents and statements made to the investing public by the Company and Mr. Ratliff misrepresented material facts regarding the business and finances of the Company. As of January 30, 2004, a written stipulation of settlement documenting the settlement terms was signed by counsel for all parties. The stipulation of settlement was presented to the Court on February 27, 2004 for a determination of initial fairness and initiation of other procedures leading to a final hearing. At the hearing, the Court granted initial approval of the settlement as proposed, and established periods for determination of the class and dates for a final settlement hearing approving disbursement of settlement funds to any class members. The settlement remains subject to court approval before becoming final. Under the settlement, the Company has paid into a settlement fund the amount of $37,500 to include all costs of administration, and has also contributed 150,000 shares of stock of Miller Petroleum, Inc. that is currently owned by the Company that had been accepted in payment of an obligation owed to the Company by Miller Petroleum. The Company also contributed to the settlement fund the Company's agreement to issue 300,000 warrants to purchase a share of the Company's common stock for a period of three years from date of issue at $1 per share. The number or price of the warrants is to be adjusted to account for the additional shares sold pursuant to the rights offering made by the Company or other stated events. All expenses including attorneys' fees as are awarded by the court on final hearing are to be paid out of the settlement funds. The parties have stipulated the existence of a class for settlement purposes only, and the existing lawsuit will be dismissed, and the class members fully release their claims, when the settlement becomes final upon subsequent order of the Court.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None during the fourth quarter of 2003.
PART II
ITEM 5.
ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
The Company's common stock is listed on the American Stock Exchange ("AMEX") 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, 2002 and December 31, 2003 are set forth below.
High Low ---- --- For the Quarters Ending
March 31, 2003 2.00 1.00
June 30, 2003 1.23 0.36
September 30, 2003 1.28 0.65
December 31, 2003 0.94 0.63
March 31, 2002 8.19 5.80
June 30, 2002 6.49 2.71
September 30, 2002 3.45 2.20
December 31, 2002 2.90 1.05
HOLDERS
As of March 16, 2004 the number of shareholders of record of the Company's common stock was 375 and management believes that there are approximately 2,899 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. The Company did not pay any dividends with respect to the Company's common stock in 2003 and 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-Q filed by the Company, no other equity securities that were not registered under the Securities Act of 1933, as amended, were sold or issued by the Company during 2003.
Management believes that all of the persons who were sold or issued common stock or preferred stock during 2003 that was not registered under the Securities Act of 1933, as amended, 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 such securities during 2003 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.
PURCHASES OF EQUITY SECURITIES BY THE COMPANY AND AFFILIATED PURCHASERS
Neither the Company or any of its affiliates repurchased any of the Company's equity securities during 2003.
THE RIGHTS OFFERING
On October 17, 2003, the Company filed a Registration Statement on Form S-1 with the SEC for a rights offering of the Company's common stock (the "Rights Offering"). On December 29, 2003; February 11, 2004; and February 13, 2004, the Company filed amendments to the Registration Statement. On February 13, 2004, the SEC deemed effective the Registration Statement on Form S-1 as amended.
The Rights Offering was a distribution to the holders of the Company's common stock outstanding at the record date, February 27, 2004, at no charge, of nontransferable subscription rights at the rate of one right to purchase three shares of the Company's common stock for each share of common stock owned at the subscription price of $0.75 in the aggregate, or $0.25 per each share purchased.
The record date for the Rights Offering was set as of February 27, 2004. The offering expired at 5:00 p.m., New York City time, on March 18, 2004.
Each subscription right in addition to the right to purchase three shares of common stock carried with it an over-subscription privilege. The over-subscription privilege provided stockholders that exercise all of their basic subscription privileges with the opportunity to purchase those shares that were not purchased by other stockholders through the exercise of their basic subscription privileges at the same subscription price per share. In no event could any subscriber purchase shares of the Company's common stock in the offering that, when aggregated with all of the shares of the Company's common stock otherwise owned by the subscriber and his, her or its affiliates, would immediately following the closing represent more than 50% of the Company's issued and outstanding shares.
As of March 30, 2004, Management intends that the net proceeds of the Rights Offering will be used initially to pay non-bank indebtedness in the aggregate amount of up to approximately $6 million (including up to $3,850,000 in principal amount plus accrued interest owed by the Company to Dolphin Offshore Partners, L.P., the general partner of which is Peter E. Salas a Director of the Company), with the balance of the net proceeds to be used to repay bank indebtedness and/or for working capital purposes, including the drilling of additional wells. See, "Item 13 -"Certain Relationships and Related Transactions."
At the time the Rights Offering closed on March 18, 2004 all 36.3 million shares offered had been subscribed for and, as a result the Company raised approximately $9.1 million. The total number of shares subscribed for actually exceeded the 36.3 million shares available for issuance under the offering. Consequently, all shares subscribed for under the basic privilege were issued and the number shares issued under the over subscription privilege was proportionately reduced to equal the number of remaining shares. The allocation and issuance of the oversubscribed shares was made by Mellon Investor Services, the Company's subscription agent who also returned payments for those oversubscribed shares that were not available.
Pursuant to the Rights Offering, 7,029,604 rights were exercised pursuant to the basic subscription privilege, resulting in the purchase of 21,088,812 shares at $0.25 per share for gross proceeds to the Company of $5,272,203. A total of 15,211,188 shares were purchased pursuant to the oversubscription privilege, resulting in additional gross proceeds to the Company of $3,802,797. See, Item 13 - Certain Relationships and Related Transactions" for a complete list of the shares purchased pursuant to the Rights Offering by Directors and Officers of the Company and entities controlled by such persons.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data has 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),
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(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 (4)(5)(6),
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 $2,815,119 ($0.24 per share) in 2003 compared to a net loss of $3,661,344 ($0.33 per share) in 2002 and compared to a net loss of $2,653,970 ($0.26 per share) in 2001.
During 2003, the Company implemented Statement of Financial Accounting Standard No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"), resulting in a gain on a cumulative effect from a change in accounting principle of $1,247,121. Additionally, the Company implemented Statement of Financial Accounting Standard No. 143, "Asset Retirement Obligations" in July 1, 2003, resulting
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(4) With respect to the pipeline facilities, during the years ended December 31, 2000 and 1999, this included portions which were under construction.
(5) No cash dividends have been declared or paid by the Company for the periods presented.
(6) On July 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150 under which mandatorily redeemable preferred stock shall be reclassified at estimated fair value to a liability. Thus, in 2003, it was determined that each of the Company's series of preferred stock qualifies as shares subject to mandatory redemption and should be classified as a liability. Also, see Note 9 to the Consolidated Financial Statements in Item 8 of this Report.
in a loss on a cumulative effect from a change in accounting principle of ($351,204). See notes to the consolidated financial statements in Item 8 of this Report.
The Company realized oil and gas revenues of $6,040,872 in 2003 as compared to $5,437,723 in 2002 and as compared to $6,656,758 in 2001. The increase in revenues in 2003 from 2002 was due to an increase in prices in 2003. Gas prices for gas produced from the Swan Creek Field averaged $5.38 per MCF in 2003 as compared to $3.22 per MCF in 2002. Oil prices for oil produced from the Swan Creek Field averaged $26.87 per barrel in 2003 as compared to $21.85 in 2002. Gas prices for gas produced from the Kansas Properties averaged $4.73 per MCF in 2003 compared to $2.96 per MCF in 2002. Oil prices for oil produced from the Kansas Properties averaged $29.00 per barrel in 2003 compared to $23.89 per barrel in 2002. The increase in prices was partially offset by a reduction in volumes produced. The Company sold 1,004,899 MCF of natural gas from Swan Creek and Kansas in 2002 compared to 620,873 MCF in 2003. The Company also sold 147,243 barrels of oil from Swan Creek and Kansas in 2003, compared to 157,973 barrels in 2002. The reason for the decrease in volumes produced in 2003 was the Company's dispute with Bank One which significantly limited the Company's ability to drill new wells and to work over under-producing wells in Kansas.
The Company's subsidiary, TPC, had pipeline transportation revenues of $163,393 in 2003, a decrease compared to of $259,677 in 2002 and $296,331 in 2001, resulting from the decrease in volumes of gas produced from the Swan Creek Field.
The Company's production costs and taxes have increased each year from 2001 to 2003 as additional costs have been incurred to maintain the Kansas Properties and to begin production from the Swan Creek Field in 2001. The production costs and taxes increased in 2003 to $3,412,201 from $3,094,731 in 2002 and from $2,951,746 in 2001. This increase was due to the fact that the Company's field personnel cost was capitalized as the Company was drilling new wells in 2001 and 2002, compared to 2003 when all employees were working to maintain production and these costs, including 2003 field salaries in Swan Creek in the amount of $279,000, were expensed. The remaining increase is due to increased property taxes on the pipeline because it has been assessed at a higher value after completion.
Depletion, depreciation, and amortization remained consistent in 2003 at $2,315,767 compared to $2,413,597 in 2002. Depletion, depreciation, and amortization in 2001 was $1,849,963. The primary increase in 2003 and 2002 levels from 2001 was due to a change in the estimate of proved reserves as set forth in the 2002 Ryder Scott report.
The Company reduced its general administrative costs to $1,486,280 in 2003 from $1,868,141 in 2002 and $2,957,871 in 2001. Management has made a significant effort to control costs in every aspect of its operations. Some of these cost reductions include the reduction of personnel from 2002 and 2001 levels and utilization of existing employees to perform drafting and file preparation services previously performed by third parties at additional cost. The Company also closed its New York office in late 2002 and a field office in Tennessee in 2003
The Company recorded an impairment loss of $459,000 relating to an oil rig in 2003.
Interest expense for 2003 increased significantly over 2002 levels due to the adoption of Financial Accounting Standards Board Statement of Financial Accounting Standards ("SFAS") No. 143 which deals with asset retirement obligations and SFAS No.150 regarding preferred stock and dividends on preferred stock being recognized as interest expense in 2003. See, "Recent Accounting Pronouncements" below. Interest expense in 2003 was $1,357,963 compared to $578,039 in 2002 and $850,965 in 2001.
Public relations costs were significantly reduced in 2003 to $31,183 compared to $193,229 in 2002 and $293,448 in 2001 as the Company applied cost saving methods in the preparation of the Annual Report and in publishing of press releases.
Professional fees in 2003 were $549,503 compared to $707,926 in 2002 and $355,480 in 2001. These fees remained at a high level due to legal and accounting services primarily related to the Bank One litigation and new accounting regulations.
Dividends on preferred stock decreased to $268,389 in 2003 from $506,789 in 2002 and from $391,183 in 2001 as a result of SFAS No.150 effective July 1, 2003. The 2003 amount reflects dividends for the first six months of 2003. The remaining dividends were charged to interest expense. See, "Recent Accounting Pronouncements" below and Note 9 to the Company's Financial Statements for more information.
LIQUIDITY AND CAPITAL RESOURCES
In November 2001, Bank One extended to the Company a line of credit of up to $35 million. The initial borrowing base under such credit agreement was $10 million. In April 2002, the Company received a notice from Bank One stating that it had redetermined and reduced the borrowing base under the credit agreement to approximately $3.1 million and requiring a $6 million reduction of the outstanding loan. The schedule of reserve reports required by the Credit Agreement upon which such redeterminations were to be based specifically established a procedure involving an automatic monthly principal payment of $200,000 commencing February 1, 2002. As of March 1, 2004, the outstanding principal balance under the credit agreement was approximately $4.5 million.
As a result of Bank One's unexpected reduction of the borrowing base and the corresponding demand for payment of $6 million, combined with the fact that the Company is still in the early stages of its oil and gas operating history during which time the Company has had a history of losses from operations and has an accumulated deficit of ($30,755,038) and a working capital deficit of ($10,710,923) as of December 31, 2003, the Company's independent auditors issued their opinion which emphasized their substantial doubt about the Company's ability to continue as a going concern on the Company's consolidated financial statements for the year ended December 31, 2003. The Company's ability to continue as a going concern depends upon
its ability to obtain long-term debt or raise capital and satisfy its cash flow requirements.
In May 2002, the Company filed suit against Bank One in Federal court in the Eastern District of Tennessee, Northeastern Division at Greeneville, Tennessee to restrain Bank One from taking any steps pursuant to the credit agreement to enforce its demand that the Company reduce its loan obligation or else be deemed in default and for actual and punitive damages resulting from the demand. See "Item 3 - Legal Proceedings" for a discussion of this action. Although the parties may continue to consider settlement of all outstanding issues, no settlement discussions are presently occurring and no settlement has been reached. The Court has adjusted the procedural schedule so that the trial of this action is scheduled to commence on December 7, 2004 in the event settlement is not concluded. Even if the Company concludes a settlement with Bank One, the Company does not anticipate that the Company will be able to either increase the borrowing base under the Bank One credit agreement or borrow any additional sums from Bank One. To fund additional drilling and to provide additional working capital, the Company is required to pursue other options. Although the Company intends to apply the net proceeds of its Rights Offering initially to repay outstanding non-bank indebtedness and to apply the balance of such proceeds, if any, to repay bank indebtedness to some extent and/or to fund the drilling of additional wells, there can be no assurances that such net proceeds will be sufficient for such purposes or that the Company will be able to resolve the difficulties currently preventing it from drilling additional wells and increasing production volumes of natural gas from the Swan Creek Field and to perform work necessary to maintain production from its Kansas Properties.
As of December 31, 2003, the Company had total stockholders' equity of $11,888,332 and total assets of $30,604,240. The Company had a net working capital deficiency at December 31, 2003 of ($10,710,923) compared to a net deficiency of ($7,998,835) at December 31, 2002.
Net cash provided by operating activities for 2003 was $314,004 as compared to net cash used in operating activities of $566,017 in 2002. The Company's net loss in 2003 increased to $3,442,647 from $3,154,555 in 2002. The impact on cash provided by operating activities was due to the net loss for 2003 and was primarily offset by non-cash depletion, depreciation, and amortization of $2,315,767, non-cash compensation and services paid by insurance of equity instruments of $93,313, loss on impairment of long-term assets of $495,000, accretion of liabilities of $454,939 and cumulative unpaid dividends of $350,453. Cash flow from working capital items in 2003 was $60,282 as compared to $126,321 in 2002. This resulted from decreases in 2003 from 2002 in accounts payable of $320,813 and in accounts receivable of $222,289 and an increase in accrued interest payable in 2003 from 2002 of $173,179.
Net cash used in operating activities increased from $221,176 in 2001 to $566,017 in 2002. The Company's net loss in 2002 increased to $3,154,555 from $2,262,787 in 2001. The impact on cash used was due to the net loss for 2001and was offset by non-cash depletion, depreciation and amortization of $2,413,597. Cash flow from working capital items in 2002 was $126,321 as compared to $232,338 in 2001. This resulted from increases from 2001 to 2002 in accounts payable of $188,597, and an increase in accrued liabilities of $31,805 and an increase in
other current assets of $58,000, partially offset by an increase in 2002 from 2001 in accounts receivable of $69,192 and an increase in inventory of $103,384.
Net cash used in investing activities amounted to $63,046 for 2003 compared to $2,889,937 for 2002. The decrease in net cash used for investing activities during 2003 was primarily attributable to the fact that in 2003 additions to oil and gas properties was $133,501 compared to $1,982,529 in 2002. In 2003 there was a reduction in expenditures used for the construction of Phase II of the pipeline system from $841,750 in 2002 to $5,775 and in 2003 the Company did not make any expenditures for additions to other property and equipment whereas in 2002 the Company expended $214,897 for these items.
Net cash used in investing activities amounted to $2,889,937 for 2002 compared to net cash used in the amount of $9,408,684 for 2001. The decrease in net cash used for investing activities during 2002 is primarily attributable to the construction of Phase II of the pipeline of $4,213,095 in 2001 as compared to $841,750 in 2002, and additions to oil and gas properties of $4,821,883 in 2001 as compared to $1,982,529 in 2002.
Net cash used in financing activities amounted to $122,422 in 2003 compared to net cash provided by financing activities of $3,246,633 in 2002. The primary sources of financing include proceeds from borrowings of $3,256,171 in 2003 compared to $2,063,139 in 2002, private placements of common stock of $250,000 in 2003 compared to $2,677,000 in 2002, convertible redeemable preferred stock of $1,303,168 in 2002 compared to none in 2003 and proceeds from the exercise of options of $47,000 in 2003 compared to none in 2002. The primary use of cash in financing activities was the repayment of borrowings of $3,432,470 in 2003 compared to $2,378,273 in 2002.
Net cash provided by financing activities decreased to $3,246,633 in 2002 from $8,419,336 in 2001. This was due to the Company's inability to enter into new financing arrangements in 2002 as a result of its dispute with Bank One as discussed above. In 2001 the primary sources of financing included proceeds from borrowings of $10,442,068 as compared to $2,063,139 in 2002, private placements of common stock of $3,900,000 in 2001 as compared to $2,677,000 in 2002, convertible redeemable preferred stock of $l,591,150 in 2001 as compared to $1,303,168 in 2002 and proceeds from exercise of options of $2,341,000 in 2001 as compared to none in 2002 as the market price of the Company's stock fell below the exercise price of the earlier granted options. The primary use of cash in financing activities in 2001 was the use of the funds received from Bank One to repay the Company's prior borrowings of $8,833,325 as compared to 2002 when cash from financing activities of $2,378,273 was used primarily to make payments to Bank One in 2002 and for working capital.
The Company must make substantial capital expenditures for the acquisition, exploration and development of oil and gas reserves. The Company is presently unable to fund the resumption of its drilling program in the Swan Creek Field. At the present time and until the Company is able to increase its production and sales of gas and to resolve its dispute with Bank One, the Company must obtain the necessary funds to proceed with its drilling program from
other sources, such as the Rights Offering as well as equity investment, bank loan or a joint venture with other companies, as to which there can be no assurances. In addition to its operational cash requirements and indebtedness to Bank One, the Company also has a significant amount of loans and other obligations which will either become due or mature on April 4, 2004 and July 31, 2004, including unsecured and convertible notes in the principal amount of approximately $1,247,000 and secured promissory notes due to Dolphin Offshore Partners, L.P. and Jeffrey N. Bailey, a Director of the Company, as of the date of this Report in the principal amount of $3,709,000 plus interest thereon. See, "Item 13 - Certain Relationships and Related Transactions". Although the Company intends to apply the net proceeds from the Rights Offering initially to repay non-bank indebtedness and to apply the balance of such proceeds, if any, to repay in part bank indebtedness and/or other working capital purposes, including the drilling of additional wells, there can be no assurances that such net proceeds will be sufficient for such purposes or that the Company will be able to resolve the financial difficulties currently preventing it from drilling wells and increasing production volumes of natural gas from the Swan Creek Field. In addition, the Company's revenues or cash flows could be reduced because of a variety of reasons, including lower oil and gas prices or the inoperability of some or all of our existing wells, as to which there can be no assurances. The Company does not know that it will be able to obtain additional funding.
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.
REVENUE RECOGNITION
The Company recognizes revenues based on actual volumes of oil and gas sold and delivered to its customers. Natural gas meters are placed at the customers' location and usage is billed each month. Crude oil is stored and at the time of delivery to the customers, revenues are recognized.
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 $480,421, $1,982,529 and $4,821,883 of these costs in 2003, 2002 and 2001, 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. 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 write-downs were recorded in 2003, 2002 or 2001.
OIL AND GAS RESERVES/DEPLETION DEPRECIATION AND AMORTIZATION OF OIL AND GAS PROPERTIES
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, 2003 were estimated by Ryder Scott, L.P., Petroleum Consultants. Projecting the effects of commodity prices on production, and timing of development expenditures include many factors beyond the Company's control. The future estimates of net cash flows from the Company's proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
ASSET RETIREMENT OBLIGATIONS
The Company is required to record the effects of contractual or other legal obligations on well abandonments for capping and plugging wells. Management periodically reviews the estimate of the timing of the wells' closure as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 12%. Quarterly, management accretes the 12% discount into the liability and makes other adjustments to the liability for well retirements incurred during the period.
CONTINGENCIES
The Company accounts for contingencies in accordance with SFAS No. 5, "Accounting Contingencies" which requires that the Company 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.
RECENT ACCOUNTING PRONOUNCEMENTS
A reporting issue has arisen regarding the application on certain provisions of Statement of Financial Accounting Standard No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") to companies in the extracting industries including oil and gas companies. The issue is whether SFAS 142 requires the registrants to classify the cost of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas properties owned and provide specific footnote disclosures. Historically, the Company had included the cost of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS 142 requires oil and gas companies to classify cost of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible asset line item on the balance sheet, the Company would be required to reclassify approximately $484,000 at December 31, 2003 and $346,000 at December 31, 2002, out of oil and gas properties and into a separate intangible asset line item. The Company's consolidated statements of net loss and cash flows would not be affected since such intangible assets would continue to be depleted and amortized for impairment in accordance with full cost accounting rules. Further, the Company does not believe the classification of the cost of mineral rights associated with extracting oil and gas as intangible assets would have any impact on compliance with covenants under its debt agreement.
In 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard No.143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company's asset retirement obligations relate primarily to the plugging
dismantlement, removal, site reclamation and similar activities of its oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its depreciation, depletion and amortization for oil and gas properties without recording a separate liability for such amounts. The Company has adopted SFAS 143 beginning on January 1, 2003, recording a cumulative loss as a result of the adoption of this statement of approximately ($351,000). During 2003, the Company recorded $73,368 in accretion cost (using a 12% accretion factor) on the asset retirement obligation. These accretion costs are included in the interest expense at December 31, 2003.
Statement of Financial Accounting Standard No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"), addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets" and for Long-Lived Assets to be Disposed Of. SFAS 144 establishes a single accounting model for long- lived assets to be disposed of by sale and expands guidance with respect to cash flow estimations. SFAS 144 became effective for the Company's fiscal year beginning January 1, 2002. The adoption of this standard did not have a material impact on the Company's financial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" ("SFAS 146"), in June 2002. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs incurred in a Restructuring)." SFAS 146 applies to costs incurred in an "exit activity", which includes, but is not limited to, re-structuring, or a "disposal activity" covered by SFAS 144. The effect of this Statement did not have a material impact on the Company.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others", an interpretation of FASB Statements No.5, 57 and 107 and a rescission of FASB Interpretation No. 34 ("FIN 45"). FIN 45 addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The disclosure requirements in FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The effect of this statement did not have a material impact on the Company.
During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46"), which requires the consolidation of certain entities that are determined to be variable interest entities ("VIE's"). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity's activities or (iii) the entity's equity neither absorbs losses or benefits from gains. The Company owns no interests in variable interest entities, and therefore this new interpretation has not affected Company's consolidated financial
statements.
In May 2003, the FASB issued Statement of Financial Accounting Standard No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity and it requires that an issuer classify a financial instrument that is within its scope as a liability. SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003 for public companies. Restatement is not permitted. Adoption of this standard during 2003, resulted in a reclassification (to a liability) and restatement (to fair value) of the Company's Series A, B and C preferred stock subject to mandatory redemption. Accordingly, for the year ended December 31, 2003, the Company recognized cumulative gain from a change in accounting principle of approximately $1,247,000. This cumulative gain results from the difference between the carrying amount of the preferred shares and the fair value of the shares after adoption. Accretion totaling $354,735 has been recognized as interest expense for the period from July 1, 2003 through December 31, 2003.
CONTRACTUAL OBLIGATIONS
- ------------------------- (7) See, Note 7 to Consolidated Financial Statements in Item 8 of this Report.
(8) See, Note 8 to Consolidated Financial Statements in Item 8 of this Report.
(9) See, Note 9 to Consolidated Financial Statements in Item 8 of this Report.
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 $23.44 per barrel to a high of $33.60 per barrel during 2003. Gas price realizations ranged from a monthly low of $3.69 per Mcf to a monthly high of $9.11 per Mcf during the same period. The Company did not enter into any hedging agreements in 2003 to limit exposure to oil and gas price fluctuations.
INTEREST RATE RISK
At December 31, 2003, the Company had debt outstanding of approximately $16.1 million including, as of that date, $5.1 million owed on its revolving credit facility with Bank One. The interest rate on the Bank One revolving credit facility is variable based on the financial institution's prime rate plus 0.25%. The Company's remaining debt of $11 million has fixed interest rates ranging from 6% to 12%. As a result, the Company's annual interest costs in 2003 fluctuated based on short-term interest rates on approximately 32% of its total debt outstanding at December 31, 2003. The impact on interest expense and the Company's cash flows of a 10 percent increase in Bank One's prime rate (approximately 0.5 basis points) would be approximately $22,000, assuming borrowed amounts under the Bank One credit facility remained at the same amount owed as of December 31, 2003. The Company did not have any open derivative contracts relating to interest rates at December 31, 2003.
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 projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future
production may vary significantly from 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 AND SUPPLEMENTARY DATA
The financial statements and supplementary data commence on page.
ITEM 9
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
ITEM 9A CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Company's disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Securities Exchange Act of 1934, as amended, including this Report, is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms.
The Company's management, including its Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended as of the date of this Report. Based on that evaluation, the Company's Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective to ensure that material information was accumulated and communicated to management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure in the Company's filings with the SEC.
CHANGES IN INTERNAL CONTROLS
There have been no change to the Company's system of internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, the Company's system of controls over financial reporting.
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 - ---- --------- --------------- Stephen W. Akos Director 2/28/03 8000 Maryland Avenue St. Louis, MO 63105
Joseph E. Armstrong Director 3/13/97 4708 Hilldale Drive Knoxville, TN 37914
Jeffrey R. Bailey Director; 2/28/03 2306 West Gallaher Ferry President 6/17/02 Knoxville, TN 37932
John A. Clendening Director 2/28/03 1031 Saint Johns Drive Maryville, TN 37801
Robert L. Devereux Director 2/28/03 10 South Brentwood Blvd. St. Louis, MO 63105
Bill L. Harbert Director 4/2/02 820 Shaders Creek Pkway Birmingham, AL 35209
Peter E. Salas Director 10/8/02 129 East 17th Street New York, NY 10003
Charles M. Stivers Director 9/28/01 420 Richmond Road Manchester, KY 40962
Richard T. Williams Director; 6/28 /02 4472 Deer Run Drive Chief Executive 2/3/03 Louisville, TN 37777 Officer
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 F. Sloan Treasurer 12/4/96 121 Oostanali Way Loudon, TN 37774
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
In fiscal 2003, Peter E. Salas, a Director of the Company, failed to timely file one Form 4 Report involving one transaction. Charles M. Stivers, a Director of the Company, and Robert M. Carter, President of TPC, recently each filed a Form 5 Report which indicated they each failed to file one Form 4 Report for fiscal 2003 involving six transactions and one transaction, respectively.
During 2003 , Malcolm E. Ratliff, the Company's former Chief Executive Officer and Chairman, owned more than 10% of the Company's outstanding stock. During 2003, it is believed that Mr. Ratliff entered into transactions with respect to the acquisition and/or disposition of the Company's stock that he owned or controlled directly or indirectly. However, the Company is not aware of the exact nature of these transactions since Mr. Ratliff, to the Company's knowledge, neither filed any reports on Form 4 or Form 5 disclosing these transactions, nor communicated the nature or extent of such transactions to the Company. Thus, the Company is not able to specify the number of Forms 4 and 5 that Mr. Ratliff failed to file, timely or otherwise, or the number of transactions not reported.
BUSINESS EXPERIENCE
DIRECTORS
Stephen W. Akos is 49 years old. He has over twenty years experience in the financial services industry with an expertise in fixed income securities. Since August of 2000, he has been First Vice President, Institutional Fixed Income Sales, Robert W. Baird & Co., St. Louis, Missouri. Prior to 2000, he held executive positions with Mercantile Bank and Mark Twain Bank since 1993. Before 1993 he was a broker and held a series of executive positions at brokerage firms Dean Witter, Shearson Lehman Hutton, Drexel Burnham Lambert, and Kidder Peabody in St. Louis. He received an MBA in Finance from Washington University in 1979, and a B.S. in Business Administration, Accounting, from Washington University in 1976. He was elected as a Director of the Company on February 28, 2003.
Joseph Earl Armstrong is 47 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. He has served as a Director of the Company since 1997.
Jeffrey R. Bailey is 46 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 and competition technology and to review analytical 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. He was elected as President of the Company on July 17, 2002 and as a Director on February 28, 2003.
Dr. John A. Clendening is 72 years old. He received B.S. (1958), M.S. (1960) and Ph. D. (1970) degrees in geology from West Virginia University. He was employed as a Palynologist-Coal Geologist at the West Virginia Geological Survey from 1960 until 1968. He joined Amoco in 1968 and remained with Amoco as a senior geological associate until 1972. Dr. Clendening has served as President and other offices of the American Association of Stratigraphic Palynologists and the Society of Organic Petrologists. From 1992 - 1998 he was engaged in association with Laird Exploration Co., Inc. of Houston, Texas, directing exploration and
production in south central Kentucky. In 1999 he purchased all the assets of Laird Exploration in south central Kentucky and operates independently. While with Amoco Dr. Clendening was instrumental in Amoco's acquisition in the early 1970's of large land acreage holdings in Northeast Tennessee, based upon his geological studies and recommendations. His work led directly to the discovery of what is now the Company's Paul Reed # 1 well. He further recognized the area to have significant oil and gas potential and is credited with discovery of the field which is now known as the Company's Swan Creek Field. Dr. Clendening previously served as a Director of the Company from September 1998 to August 2000. He was again elected as a Director of the Company on February 28, 2003.
Robert L. Devereux is 44 years old. He graduated in 1982 from St. Louis University with a Bachelor's Degree in Business Administration with a major in finance. He received his law degree from St. Louis University in 1985. For the past eighteen years, Mr. Devereux has been actively engaged in the practice of law, specializing in commercial litigation. Since 1994, he has been a principal in the law firm of Devereux Murphy LLC located in St. Louis, Missouri. For the past eight years Mr. Devereux has also been a principal of and has served as the Chief Executive Officer of Gateway Title Company, Inc. He was elected as a Director of the Company on February 28, 2003.
Bill L. Harbert is 80 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. He was elected as a Director of the Company on April 2, 2002.
Peter E. Salas is 49 years old. He has been President of Dolphin Asset Management Corp. and its related companies since he founded it in 1988. Prior to establishing Dolphin, he was with J.P. Morgan Investment Management, Inc. for ten years, becoming Co- manager, Small Company Fund and Director-Small Cap Research. He received an A.B. degree in Economics from Harvard in 1976. Mr. Salas was elected to the Board of Directors on October 8, 2002.
Charles M. Stivers is 41 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. Mr. Stiver's firm specializes in the oil and gas industry and has clients in eight states. The oil and gas work performed by his firm includes all forms of SEC audit work, SEC quarterly financial statement filings, oil and gas consulting work and income tax services. Mr. Stiver's 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.
Dr. Richard T. Williams is 53 years old. He has been a member of the faculty of the Department of Geological Sciences at The University of Tennessee in Knoxville, Tennessee, since 1987, after holding faculty positions at West Virginia University and the University of South Carolina since 1979. He has been engaged in reflection seismology and geophysical studies in the Appalachian Overthrust since 1980. He earned his Ph.D. in Geophysics from Virginia Tech in 1979. Dr. Williams was elected to the Board of Directors of the Company effective June 28, 2002. He was appointed Chief Operating Officer of the Company on January 10, 2003, and on February 3, 2003, he was elected Chief Executive Officer of the Company.
OFFICERS
Mark A. Ruth is 45 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 67 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 55 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 General Counsel of the Company since July 9, 1999.
Sheila F. Sloan is 48 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.
COMMITTEES
The Company's Board has operating audit, stock option, compensation, field safety and frontier exploration committees. Charles M. Stivers, Stephen W. Akos and John A. Clendening are the members of the Company's Audit Committee. Mr. Stivers is the Chairman of this Committee and the Board of Directors has determined that Mr. Stivers is an "audit committee financial expert" as defined by applicable SEC regulations. Robert L. Devereux, John A. Clendening and Mr. Akos comprise the stock option committee with Mr. Devereux acting as Chairman; Messrs. Akos, Stivers and Clendening comprise the compensation committee with Mr. Clendening acting as Chairman; Richard T. Williams, Jeffrey R. Bailey and Joseph Earl Armstrong comprise the field safety committee; and Messrs. Williams, Bailey and Clendening comprise the frontier exploration committee.
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 the 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, commodities, securities or banking activities;
(4) Was found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission ("CFTC") to have violated any federal or state securities law or Federal commodities law, and the judgment in such civil action or finding by the SEC or CFTC has not been subsequently reversed, suspended, or vacated.
CODE OF ETHICS
The Company's Board of Directors has adopted a Code of Ethics that applies to the Company's Chief Executive Officer, financial officers and executive officers, including its President and Chief Financial Officer. A copy of this Code of Ethics can be found at the Company's internet website at www.Tengasco.com. The Company intends to disclose any amendments to its Code of Ethics, and any waiver from a provision of the Code of Ethics granted to the Company's Chief Executive Officer, President, Chief Financial Officer, or persons performing similar functions, on the Company's Internet website within five business days following such amendment or waiver. The information contained on or connected to the Company's Internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that the Company files with or furnishes to the SEC.
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, 2003, December 31, 2002 and December 31, 2001. None of the Company's other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity during those periods.
SUMMARY COMPENSATION TABLE
OPTION GRANTS IN LAST FISCAL YEAR
INDIVIDUALIZED GRANTS
================================================================================ NAME NUMBER OF PERCENT OF TOTAL EXERCISE EXPIRATION SECURITIES OPTIONS/SARS OR BASE DATE UNDERLYING GRANTED TO PRICE OPTIONS/SARS EMPLOYEES IN ($/SH) GRANTED (#) FISCAL 2003 - -------------------------------------------------------------------------------- Richard T. Williams 60,000 13.8% $0.50 05/06/06 ================================================================================
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(10) Malcolm E. Ratliff served as the Company's Chief Executive Officer throughout 2002. Richard T. Williams, the Company's current Chief Executive Officer replaced Mr. Ratliff on February 3, 2003.
(11) Number of shares underlying options has been retroactively adjusted for a 5% stock dividend declared by the Company as of September 4, 2001.
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, 2003.
AGGREGATE OPTION EXERCISES FOR FISCAL 2003 AND YEAR END OPTION VALUES
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 is considering adopting a 401(k) plan and full liability insurance for directors and executive officers. However, there are no immediate plans to do so at this time.
COMPENSATION OF DIRECTORS
The Board of Directors has resolved to compensate members of the Board of Directors for
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(12) 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 $0.75 per share on December 31, 2003, as reported by The American Stock Exchange. The exercise price of the unexercised option granted to Richard T. Williams, the Chief Executive Officer of the Company, in 2003 was $0.50. Prior to his becoming Chief Executive Officer of the Company. Dr. Williams on August 5, 2002 was granted an option to purchase 13,125 shares of the Company's common stock at a price of $2.69 per shares. That option expires on August 4, 2005. Since the exercise price of shares underlying that option had a negative value as of December 31, 2003 they are not included in this chart.
(13) 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. On June 18, 2003, Dr. Williams exercised his option to the extent of purchasing 10,000 shares of the Company's common stock at $0.50 per share. The closing price of the Company's common stock on June 18, 2003 as reported on by the American Stock Exchange was $1.20 per share.
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.
Directors who are on the Company's Audit, Compensation and Stock Option Committees are independent and therefore, do not receive any consulting, advisory or compensatory fees from the Company. However, such Board members may receive fees from the Company for their services on those committees. The Company intends to implement a plan for the payment of those committee members for their services on an annual basis.
EMPLOYMENT CONTRACTS
The Company has entered into an employment contract with its Chief Executive Officer, Richard T. Williams for a period of two years through December 31, 2004 at an annual salary of $80,000. 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 relationships 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 25, 2004 with these computations being based upon 48,677,828 shares of common stock being outstanding
as of that date and as to each shareholder, as it may pertain, assumes the exercise of options or warrants or the conversion of preferred stock granted or held by such shareholder as of March 25, 2003.
FIVE PERCENT STOCKHOLDERS(14) -------------------------
NUMBER OF SHARES PERCENT OF NAME AND ADDRESS TITLE BENEFICIALLY OWNED CLASS - ---------------- ----- ------------------ ----- Dolphin Offshore Stockholder 16,540,140(15) 33.9% Partners, L.P. 129 East 17th Street New York, NY 10003
SC Fundamental Value Stockholder 4,767,800(16) 9.79% Fund, L.P. 747 Third Avenue, 27th Fl. New York, NY 10017
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(14) Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of March 25, 2004 and reflect the results of the Company's Rights Offering (See, Item 5 above) to the extent known as of March 30, 2004, the date of the filing of this Report. Because the Rights Offering closed on March 18, 2004, and the shares issued thereunder were issued only days before the filing of this Report, shareholders acquiring shares under the Rights Offering may not have had sufficient time to receive either the shares or notification of the number of shares they were to receive pursuant to the basic and oversubscription privileges contained in the Rights Offering. Thus, shareholders may not have had sufficient time prior to the filing of this Report to file any forms required as a result of being or becoming a holder of as much as 5% of the Company's shares, or to inform the Company of such an occurrence. However, the Company is unaware at the time of this filing of any specific person that is or may be a five percent stockholder that is not listed in this section.
(15) Consists of 16,244,452 shares held directly by Dolphin Offshore Partners, L.P. ("Dolphin") of which Peter E. Salas, a Director of the Company, is the general partner and controlling person; a warrant held by Dolphin to purchase 10,500 shares at $7.98 per share; 117,188 shares underlying 9,000 shares of the Company's Series B 8% Cumulative Convertible Preferred Stock held directly by Dolphin; and, 168,000 shares held directly by Peter E. Salas.
(16) Ownership of shares reported on Schedule 13G filed with the SEC by a group consisting of SC Fundamental Value Fund , L.P., SC Fundamental LLC, SC-BVI Partners, PMC-BVI, Inc., SC Fundamental Value BVI, Inc., Peter M. Collery and Neil H. Koffler.
Malcolm E. Ratliff Stockholder UNKNOWN(17) UNKNOWN 1200 Scott Lane Knoxville, TN 37922
DIRECTORS AND OFFICERS(18)
NUMBER OF SHARES PERCENT NAME AND ADDRESS TITLE BENEFICIALLY OWNED OF CLASS
Stephen W. Akos Director 71,949(19) Less than 1% 8000 Maryland Avenue St. Louis, MO 63105
Joseph Earl Armstrong Director 39,450(20) Less than 1% 4708 Hilldale Drive Knoxville, TN 37914
Jeffrey R. Bailey Director; 149,412(21) Less than 1% 2306 West Gallaher Ferry President Knoxville, TN 37932
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(17) For the reasons stated below, it is not possible for the Company to determine whether the number of shares held as of March 25,2004 by Malcolm E. Ratliff does, or does not, exceed five percent of the Company's stock. Mr. Ratliff, formerly the Company's Chief Executive Officer and Chairman of the Board of Directors and a former Director of the Company, has previously reported that he is the sole shareholder and President of Industrial Resources Corporation (" IRC"); that Malcolm E. Ratliff's wife, Linda Ratliff, is the Secretary of IRC; and that accordingly, IRC may be deemed to be an affiliate of the Company. Mr. Ratliff also previously reported that although his father, James Ratliff, is the sole shareholder and President of Ratliff Farms, Inc., he is the Vice- President/Secretary of Ratliff Farms and 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. As a result of this information, Mr. Ratliff was reported by the Company to own more than 10% of the Company's common stock. Although the Company believes there may have been changes with respect to the information previously reported, it is not able to accurately disclose this information because it is not aware of any Forms 4 or 5 that to the Company's knowledge have been filed by Mr. Ratliff, IRC, or Ratliff Farms. See " Item 10 - Section 16(a) Beneficial Ownership Reporting Compliance" set forth above.
(18) Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of March 25, 2004 and reflect the results of the Company's recent Rights Offering to shareholders of record February 27, 2004.
(19) Consists of 71,949 shares held directly (certain of which are jointly owned with spouse).
(20) Consists of 4,950 shares held directly and options to purchase 34,500 shares.
(21) Consists of 76,287 shares held directly and an option to purchase 73,125 shares.
John A. Clendening Director 100,000(22) Less than 1% 1031 Saint Johns Drive Maryville, TN 37801
Robert L. Devereux Director 477,834(23) Less than 1% 10 South Brentwood Blvd. St. Louis, MO 63105
Bill L. Harbert Director 1,513,496(24) 3.1% 820 Shaders Creek Pkwy. Birmingham, AL 35209
Peter E. Salas Director 16,540,140(25) 33.9% 129 East 17th Street New York, NY 10003
Charles M. Stivers Director 13,125(26) Less than 1% 420 Richmond Road Manchester, KY 40962
Richard T. Williams Director; 263,125(27) Less than 1% 4477 Deer Run Drive Chief Executive Louisville, TN Officer
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(22) Consists of shares held directly.
(23) Consists of 410,574 shares held directly with his spouse and 67,260 shares owned by a limited liability company. Shares owned by the limited liability company have been adjusted to reflect Mr. Devereux's ownership interest in the shares owned by the limited liability company.
(24) Consists of 1,428,942 shares held directly, 71,429 shares underlying 5,000 shares of the Company's Series A 8% Cumulative Convertible Preferred Stock held directly and an option to purchase 13,125 shares.
(25) Consists of 168,000 shares held directly, 16,244,452 shares held directly by Dolphin Offshore Partners, L.P. ("Dolphin") of which Peter E. Salas is the general partner and controlling person; a warrant held by Dolphin to purchase 10,500 shares at $7.98 per share; and, 117,188 shares underlying 9,000 shares of the Company's Series B 8% Cumulative Convertible Preferred Stock held by Dolphin which is convertible into the Company's Common Stock.
(26) Consists of shares underlying an option.
(27) Consists of 250,000 shares held directly and options to purchase 13,125 shares.
Robert M. Carter President 20,921(28) Less than 1% 760 Prince Georges Parish Tengasco Pipeline Knoxville, TN 37922 Corporation
Mark A. Ruth Chief Financial 69,287(29) Less than 1% 9400 Hickory Knoll Lane Officer Knoxville, TN 37931
Cary V. Sorensen General Counsel; 47,875(30) Less than 1% 509 Bretton Woods Dr. Secretary Knoxville, TN 37919
Sheila F. Sloan Treasurer 6,037(31) Less than 1% 121 Oostanali Way Loudon, TN 37774
All Officers and 19,312,651(32) 39.3% Directors as a group
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.
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(28) Consists of 7,796 shares held directly and options to purchase 13,125 shares.
(29) Consists of 100 shares held directly and options to purchase 69,187 shares.
(30) Consists of shares underlying options.
(31) Consists of 2,100 shares held directly and options to purchase 3,937 shares.
(32) Consists of shares held directly and indirectly by management, shares held by Dolphin, 281,124 shares underlying options, 10,500 shares underlying warrants and 188,617 shares underlying convertible preferred stock.
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 during 2003, 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.
The Company's Board of Directors has not adopted any general policy with respect to these transactions, many of which were effected on behalf of the Company by senior management prior to consideration of the transaction by the Board of Directors in light of senior management's perceived urgency of the funding requirements, the availability of alternative sources and the terms of such transactions, which senior management viewed as at least as favorable to the Company as could have been obtained through arms-length negotiations with unaffiliated third parties. In each of the loans to the Company by Dolphin Offshore Partners, L.P. ("Dolphin), which owns more than ten percent of the Company's outstanding Common Stock and whose general partner, Peter E. Salas, is a Director of the Company, Mr. Salas negotiated with on behalf of Dolphin with senior management of the Company as to the terms thereof and did not participate in any Board action with respect thereto.
On January 8, 2003, Bill Harbert, who at the time owned more than ten percent of the Company's outstanding Common Stock and is a Director of the Company, purchased 227,275 shares of the Company's Common Stock from the Company in a private placement at a price of $1.10 per share. The proceeds from this sale were used by the Company to pay the principal and interest due to Bank One for January, 2003 and to provide working capital for the Company's operations. The market price of the Company's common stock as measured by the closing price on the American Stock Exchange on January 7, 2003, the date of the transaction, was $1.20 per share. Management believes that this sale was made on terms at least as favorable to the Company as could have been obtained through arms-length negotiations with unaffiliated third parties.
On February 3, 2003 and February 28, 2003, Dolphin loaned the Company the sum of $250,000 on each such date which the Company used to pay the principal and interest due to Bank One for February and March 2003 and for working capital. Each of these loans is evidenced by a separate promissory note each bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable due on January 4, 2004. The obligations under these loans are secured by an undivided 10% interest in the Company's Tennessee and Kansas pipelines.
On May 20, 2003, Dolphin loaned the Company the sum of $750,000 and Jeffrey R. Bailey, the President and a Director of the Company, loaned the Company $84,000, which aggregate amount of $834,000 was used to pay the principal and interest due to Bank One for June 2003 and for
working capital. These loans are evidenced by separate promissory notes bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance due on January 4, 2004. The obligations under the loans are secured by an undivided 30% and 3.36% interest, respectively, in the Company's Tennessee and Kansas pipelines.
On August 6, 2003, Dolphin loaned the Company the sum of $150,000, which was used for working capital. This loan is evidenced by a separate promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance due on January 4, 2004. The obligations under the loan are secured by an undivided 6% interest in the Company's Tennessee and Kansas pipelines
From December 2002 through December 9, 2003, Dolphin acquired a total of an 85% undivided interest in the Company's Tennessee and Kansas pipelines as collateral for a series of seven loans. In the first five of these transactions, Peter E. Salas, a Director and the general partner and controlling person of Dolphin, negotiated the terms of the loans directly with management, which terms were approved by management in view of the Company's immediate needs, financial condition and prospective alternatives and under circumstances in which Dolphin was not generally engaged in the business of lending money. These loans were made on terms that management believes were at least as favorable to the Company as it could have obtained through arms-length negotiations with unaffiliated third parties. The Company's Board approved the sixth and seventh loans on December 3 and 9, 2003, in the amounts of $225,000 and $250,000, respectively, with no participation by Mr. Salas in the meeting or the vote, which was unanimous by the seven other Directors present at the meeting. In addition, the Company has entered into a continuing security agreement, which was approved by the Board with no participation by Mr. Salas in the meeting or vote, which was unanimous by the seven other Directors present at the meeting, providing the terms of Dolphin's security interest collateralizing all of its loans.
On December 24, 2003, Dolphin loaned the sum of $1,000,000 which was used for working capital and to pay all interest and principal in full of the 1998 convertible loan to the Company refereed to as the Lutheran note then being held by several persons. This loan is evidenced by a separate promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable on April 4, 2004. The obligations under the loan are secured by an undivided interest in the Company's Tennessee and Kansas pipelines and the security agreement referred to above.
On February 2, 2004, Dolphin loaned the Company the sum of $225,000 which was used for making payment of principal and interest to Bank One for February, 2004. This loan is evidenced by a separate promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable on April 4, 2004. The obligations under the loan are secured by an undivided interest in the Company's Tennessee and Kansas pipelines and the security agreement referred to above.
From April 1 through June 30, 2003, the Company issued 10,363 shares of its common stock to holders of the Company's Series A 8% Cumulative Convertible Preferred Stock in lieu of cash quarterly interest payments due to those holders, with such shares valued at the market price thereof.
Also during that period, certain members of the Company's Board of Directors exercised options granted to them pursuant to the Tengasco, Inc. Stock Incentive Plan and purchased the following number of shares of the Company's common stock at the exercise price of $0.50 per share. Richard T. Williams - 10,000 shares, Bill L. Harbert - 24,000 shares and John A. Clendening - 24,000 shares.
The following table sets forth the number of shares of Common Stock purchased in connection with the Rights Offering by the Company's Directors, Officers and owners of more than ten percent of the Company's outstanding Common Stock. See, "Item 5 - Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - The Rights Offering"
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
The Company has no parent.
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(33) Consists of 352,012 shares purchased directly with his spouse and 60,445 shares purchased by a limited liability company. The shares purchased by the limited liability company have been adjusted to reflect Mr. Devereux's beneficial ownership interest in the shares purchased by the limited liability company.
(34) Peter E. Salas, a Director of the Company, is the general partner and controlling person of Dolphin Offshore Partners, L.P.
(35) Consists of 14,104,732 shares purchased directly by Dolphin Offshore Partners, L.P. and 144,000 shares purchased by Peter E. Salas.
ITEM 14
ITEM 14 PRINCIPAL ACCOUNTANTS FEES AND SERVICES
The following table presents the fees for professional audit services rendered by BDO Seidman, LLP for the audit of the Company's annual consolidated financial statements for the fiscal years ended December 31, 2003 and December 31, 2002, and fees for other services rendered by BDO Seidman, LLP during those periods:
Fee Category Fiscal 2003 Fiscal 2002
Audit Fees $209,310 $160,530
Audit-Related Fees $0 $0
Tax Fees $0 $0
All Other Fees $7,250 $8,950
Total Fees $216,560 $189,480
Audit fees include fees related to the services rendered in connection with the annual audit of the Company's consolidated financial statements, the quarterly reviews of the Company's quarterly reports on Form 10-Q and the reviews of and other services related to registration statements and other offering memoranda.
Audit-related fees are for assurance and related services by the principal accountants that are reasonably related to the performance of the audit or review of the Company's financial statements.
Tax Fees include (i) tax compliance, (ii) tax advice, (iii) tax planning and (iv) tax reporting.
All Other Fees includes fees for all other services provided by the principal accountants not covered in the other categories such as litigation support, etc. In 2003, the amount of fees in this category were significantly higher than in 2002 primarily due to the inclusion of fees for services performed by BDO Seidman, LLP in connection with the Company's filling of a registration statement on Form S-1 with the SEC for the Rights Offering.
All of the services for 2002 and 2003 were performed by the full-time, permanent employees of BDO Seidman, LLP
All of the 2003 services described above were approved by the Audit Committee pursuant to the SEC rule that requires audit committee pre-approval of audit and non-audit services provided by the Company's independent auditors to the extent that rule was applicable during fiscal year 2003. The Audit Committee has considered whether the provisions of such services, including non-audit services,
by BDO Seidman, LLP is compatible with maintaining BDO Seidman, LLP's independence and has concluded that it is.
PART IV
ITEM 15
ITEM 15 EXHIBITS FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
A. The following documents are filed as part of this Report:
1. Financial Statements: Consolidated Balance Sheets Consolidated Statements of Loss Consolidated Statements of Stockholders' Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements
2. Financial Schedules:
Schedules have been omitted because the information required to be set forth therein is not applicable or is included in the Consolidated Financial Statements or notes thereto.
3. Exhibits.
The following exhibits are filed with, or incorporated by reference into this Report:
Exhibit Number Description - -------------- ----------- 3.1 Charter (Incorporated by reference to Exhibit 3.7 to the registrant's registration statement on Form 10-SB filed August 7, 1997 (the "Form 10-SB"))
3.2 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) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
3.3 Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to Exhibit 3.9 to the registrant's annual report on Form 10-KSB filed April 15, 1999 (the "1998 Form 10-KSB"))
3.4 Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form 10-KSB)
3.5 Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to Exhibit 3.11 to the registrant's annual report on Form 10-KSB filed April 14, 2000 (the "1999 Form 10-KSB"))
3.6 By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
4.1 Form of Rights Certificate Incorporated by reference to registrant's statement on Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the "Form S- 1")
10.1 Purchase Agreement with IRC (Incorporated by reference to Exhibit 10.1(a) to the Form 10-SB)
10.2 Amendment to Purchase Agreement with IRC (Incorporated by reference to Exhibit 10.1(b) to the Form 10-SB)
10.3 General Bill of Sale and Promissory Note (Incorporated by reference to Exhibit 10.1(c) to the Form 10-SB)
10.4 Compensation Agreement - M.E. Ratliff (Incorporated by reference to Exhibit 10.2(a) to the Form 10-SB)
10.5 Compensation Agreement - Jeffrey D. Jenson (Incorporated by reference to Exhibit 10.2(b) to the Form 10-SB)
10.6 Compensation Agreement - Leonard W. Burningham (Incorporated by reference to Exhibit 10.2(c) to the Form 10-SB)
10.7 Agreement with the Natural Gas Utility District of Hawkins County, Tennessee (Incorporated by reference to Exhibit 10.3 to the Form 10-SB)
10.8 Agreement with Powell Valley Electric Cooperative, Inc. (Incorporated by reference to Exhibit 10.4 to the Form 10-SB)
10.9 Agreement with Enserch Energy Services, Inc. (Incorporated by reference to Exhibit 10.5 to the Form 10-SB)
10.10 Amendment Agreement dated October 19, 1999 between Tengasco, Inc. and the Natural Gas Utility District of Hawkins County, Tennessee (Incorporated by reference to Exhibit 10.9 to the registrant's current report on Form 8-K filed October 25, 1999)
10.11 Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the registrant's current report on Form 8-K filed November 23, 1999)
10.12 Agreement between A.M. Partners LLC and Tengasco, Inc. dated October 6, 1999 (Incorporated by reference to Exhibit 10.11 to the registrant's 1999 Form 10-KSB) 10.13 Agreement between Southcoast Capital LLC and Tengasco, Inc. dated February 25, 2000 (Incorporated by reference to Exhibit 10.12 to the registrant's 1999 Form 10- KSB)
10.14 Franchise Agreement between Powell Valley Utility District and Tengasco, Inc. dated January 25, 2000 (Incorporated by reference to Exhibit 10.13 to the registrant's 1999 Form 10-KSB)
10.15 Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March 27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant's 1999 Form 10-KSB)
10.16 Loan Agreement between Tengasco Pipeline Corporation and Morita Properties, Inc. dated August 16, 2000 (Incorporated by reference to Exhibit 10.15 to the registrant's current report on Form 8-K dated August 22, 2000 (the "2000 8-K"))
10.17 Promissory note made by Tengasco Pipeline Corporation and Morita Properties, dated August 16, 2000 (Incorporated by reference to Exhibit 10.15(a) to the 2000 8- K)
10.18 Throughput Agreement between Tengasco Pipeline Corporation and Morita Properties, dated August 16, 2000 (Incorporated by reference to Exhibit 10.15(b) to the 2000 8-K)
10.19 Loan Agreement between Tengasco Pipeline Corporation and Edward W.T. Gray III dated August 16, 2000 (Incorporated by reference to Exhibit 10.16 to the 2000 8-K) 10.20 Promissory note made by Tengasco Pipeline Corporation and Edward W.T. Gray III dated August 16, 2000 (Incorporated by reference to Exhibit 10.16(a) to the 2000 8- K)
10.21 Throughput Agreement between Tengasco Pipeline Corporation and Edward W.T. Gray III dated August 16, 2000 (Incorporated by reference to Exhibit 10.16(b) to the 2000 8-K)
10.22 Loan Agreement between Tengasco Pipeline Corporation and Malcolm E. Ratliff dated August 16, 2000 (Incorporated by reference to Exhibit 10.17 to the 2000 8-K)
10.23 Promissory note made by Tengasco Pipeline Corporation and Malcolm E. Ratliff dated August 16, 2000 (Incorporated by reference to Exhibit 10.17(a) to the 2000 8- K)
10.24 Throughput Agreement between Tengasco Pipeline Corporation and Malcolm E. Ratliff dated August 16, 2000 (Incorporated by reference to Exhibit 10.17(b) to the 2000 8-K)
10.25 Loan Agreement between Tengasco Pipeline Corporation and Charles F. Smithers, Jr. dated August 16, 2000 (Incorporated by reference to Exhibit 10.18 to the 2000 8- K)
10.26 Promissory note made by Tengasco Pipeline Corporation and Charles F. Smithers, Jr. dated August 16, 2000 (Incorporated by reference to Exhibit 10.18(a) to the 2000 8-K)
10.27 Throughput Agreement between Tengasco Pipeline Corporation and Charles F. Smithers, Jr. dated August 16, 2000 (Incorporated by reference to Exhibit 10.18(b) to the 2000 8-K)
10.28 Loan Agreement between Tengasco Pipeline Corporation and Nick Nishiwaki dated August 16, 2000 (Incorporated by reference to Exhibit 10.19 to the 2000 8-K)
10.29 Promissory note made by Tengasco Pipeline Corporation and Nick Nishiwaki dated August 16, 2000 (Incorporated by reference to Exhibit 10.19(a) to the 2000 8-K) 10.30 Throughput Agreement between Tengasco Pipeline Corporation and Nick Nishiwaki dated August 16, 2000 (Incorporated by reference to Exhibit 10.19(b) to the 2000 8- K)
10.31 Memorandum Agreement between Tengasco, Inc. and the University of Tennessee dated February 13, 2001 (Incorporated by reference to Exhibit 10.19 to the registrant's annual report on Form 10-KSB filed April 10, 2001 (the "2000 Form 10- KSB"))
10.32 Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems Inc. dated March 30, 2001 (Incorporated by reference to Exhibit 10.20 to the 2000 Form 10-KSB)
10.33 Reducing and 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 (Incorporated by reference to Exhibit 10.21 to the registrant's quarterly report on Form 10-Q filed November 14, 2001)
10.34 Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the registrant's registration statement on Form S-8 filed October 26, 2000)
10.35 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated October 7, 2002 in the principal amount of $500,000 (Incorporated by reference to Exhibit 10.35 to the Form S-1)
10.36 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 4, 2002 in the principal amount of $250,000 (Incorporated by reference to Exhibit 10.36 to the Form S-1)
10.37 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to
Dolphin Offshore Partners, LP dated February 3, 2003 in the principal amount of $250,000 (Incorporated by reference to Exhibit 10.37 to the Form S-1)
10.38 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated February 28, 2003 in the principal amount of $250,000 (Incorporated by reference to Exhibit 10.38 to the Form S-1)
10.39 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 20, 2003 in the principal amount of $750,000 (Incorporated by reference to Exhibit 10.39 to the Form S-1)
10.4 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated August 6, 2003 in the principal amount of $150,000 (Incorporated by reference to Exhibit 10.40 to the Form S-1)
10.41 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Jeffrey R. Bailey dated May 20, 2003 in the principal amount of $84,000 (Incorporated by reference to Exhibit 10.41 to the Form S-1)
10.42 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 3, 2003 in the principal amount of $225,000 (Incorporated by reference to Exhibit 10.42 to the registrant's current report on Form 8-K dated December 3, 2003 (the "2003 Form 8-K")
10.43 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 9, 2003 in the principal amount of $250,000 (Incorporated by reference to Exhibit 10.43 to the 2003 Form 8-K)
10.44 Continuing Security Agreement dated December 3, 2003 by the Company and Tengasco Pipeline Corporation as Obligors and Dolphin Offshore Partners, LP as Secured Party (Incorporated by reference to Exhibit 10.44 to the 2003 Form 8-K)
10.45 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 24, 2003 in the principal amount of $1,000,000 (Incorporated by reference to Exhibit 10.45 to the Form S-1) 10.46 Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Jeffrey R. Bailey dated February 2, 2004 in the principal amount of $225,000 (Incorporated by reference to Exhibit 10.46 to the Form S-1)
14* Code of Ethics
21 List of subsidiaries (Incorporated by reference to Exhibit 21 to the registrant's annual report on Form 10-K filed March 31, 2003 (the "2002 Form 10-KSB"))
23.1* Consent of Ryder Scott Company, L.P.
31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
32.1* Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2* Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* Exhibit filed with this Report
B. Reports on Form 8-K:
During the fourth quarter of 2003 the Company filed or furnished the following Current
Reports on Form 8-K.
(1) A report filed October, 2003 which included, under Item 5, an announcement that on October 17, 2003 the Company had filed a registration statement with the Securities and Exchange Commission with respect to a proposed rights offering to shareholders of the Company.
(2) A report filed December 19, 2003 which included, under Item 2, an announcement that the Company's Board of Directors authorized management to execute additional promissory notes to consolidate and extend $1.65 million of existing indebtedness payable to Dolphin and to borrow up to $1.7 million in additional funds from Dolphin.
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: March 30, 2004
TENGASCO, INC. (Registrant)
By: s/Richard T. Williams ---------------------- Richard T. Williams, 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/Stephen W. Akos Director March 30, 2004 - ----------------- Stephen W. Akos
s/Joseph Earl Armstrong Director March 30, 2004 - ----------------------- Joseph Earl Armstrong
s/Jeffrey R. Bailey Director; March 30, 2004 - ------------------- Jeffrey R. Bailey President
s/John A. Clendening Director March 30, 2004 - -------------------- John A. Clendening
s/Robert L. Devereux Director March 30, 2004 - -------------------- Robert L. Devereux
s/Bill L. Harbert Director March 30, 2004 - ----------------- Bill L. Harbert
Director - ---------------- Peter E. Salas
s/Charles M. Stivers Director March 30, 2004 - -------------------- Charles M. Stivers
s/Richard T. Williams Director; March 30, 2004 - --------------------- Chief Executive Officer Richard T. Williams
s/Mark A. Ruth Principal Financial March 30, 2004 - -------------- and Accounting Officer Mark A. Ruth
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
TENGASCO, INC. AND SUBSIDIARIES
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CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
TENGASCO, INC. AND SUBSIDIARIES
CONTENTS
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INDEPENDENT AUDITORS' REPORT
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance sheets -F-4
Consolidated Statements of loss
Consolidated Statements of stockholders' equity
Consolidated Statements of cash flows -F-8
Notes to consolidated financial statements -F-38
BDO Seidman, LLP Letterhead
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, 2003 and 2002, and the related consolidated statements of loss, stockholders' equity and comprehensive loss and cash flows for each of the three years in the period ended December 31, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 1 to the financial statements, the Company has suffered recurring losses from operations and, at December 31, 2003, has an accumulated deficit of $30,755,038 and a working capital deficit of $10,710,923. Additionally, during 2002 the Company's primary lender classified the remaining outstanding balance as immediately due and payable. The working capital deficiency has resulted in the Company's inability to pay cumulative dividends and mandatory redemption requirements on the Company's shares subject to mandatory redemption. 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 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As discussed in Notes 9 & 10 to the consolidated financial statements, the Company implemented the provisions of Statement of Financial Accounting Series No. 143, "Asset Retirement Obligations" on January 1, 2003 and the provisions of Statement of Financial Accounting Series No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" on July 1, 2003.
/s/ BDO Seidman, LLP
Atlanta, Georgia February 27, 2004, except for Note 14, which is as of March 27, 2004
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF LOSS
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SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE LOSSES
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SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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1. GOING CONCERN The accompanying consolidated financial UNCERTAINTY statements 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 and assume 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 $30,755,038 and a working capital deficit of $10,710,923 as of December 31, 2003. During 2002, the Company was informed by its primary lender that the entire amount of its outstanding credit facility was immediately due and payable, as provided for in the Credit Agreement (see Note 7). 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. Although the Company has been paying $200,000 per month plus accrued interest since April 2002. The Company is still considered to be in default by the bank. Accordingly, these $200,000 payments have put a strain on the Company's ability to pay other obligations as they become due and have hampered the Company's ability to continue its acquisition, exploration and development program. In October 2003, the Company was unable to begin the scheduled Redemption payment of $143,395 per quarter of the Series A shares and as accrued on cumulative dividends totaling $600,738 on the Series A, B and C preferred stock. These circumstances raise substantial doubt about the Company's ability to continue as a going concern.
Management's plans with regards to this uncertainty primarily relate to the issuance of additional common stock and to acquire access to other forms of lender financing. On February 13, 2004, the Company filed an amended Form S-1 with the Securities and Exchange Commission issuing rights to existing shareholders to purchase up to 3 shares (for each share owned) of the Company's common stock for $0.25 per share. See Note 14 to the Company's Consolidated Financial Statements which summarizes the results of the Rights Offering. Additionally, management is continuing to explore other avenues of lender financing at more favorable terms in order to reduce financing expenditures in the future. With the anticipation of the rights offering proceeds and more favorable debt positions, management hopes to obtain sufficient cash flows in the future to recommence their drilling program in order to maximize sales of oil and gas volumes to their customers.
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2. SUMMARY OF ORGANIZATION SIGNIFICANT ACCOUNTING POLICIES Tengasco, Inc. (the "Company"), a publicly held 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.
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.
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.
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REVENUE RECOGNITION
The Company recognizes revenues based on actual volumes of oil and gas sold and delivered to its customers. Natural gas meters are placed at the customers' location and usage is billed each month. Crude oil is stored and at the time of the delivery to the customers, revenues are recognized.
CASH AND CASH EQUIVALENTS
The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.
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. Other comprehensive income/(losses) of $25,500 and ($115,500) were recorded during the years ended December 31, 2003 and 2002, respectively resulting from a decrease in the fair value of the securities. Accumulated other comprehensive losses were ($90,000) and ($115,500) at December 31, 2003 and 2002, respectively.
INVENTORY
Inventory consists primarily of crude oil in tanks and is carried at market value.
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 equipping and closing 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.
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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. These reserves were estimated by Ryder Scott Company, Petroleum Consultants in 2001, 2002 and 2003.
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 write-downs were recorded in 2003, 2002 or 2001.
PIPELINE FACILITIES
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.
OTHER PROPERTY AND EQUIPMENT AND LONG - LIVED ASSETS
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. Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value. At December 31, 2003, management believes that carrying amounts of all of the Company's long-lived assets will be fully
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recovered over the course of the Company's normal future operations.
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), 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 for the years ended December 31, 2003, 2002 and 2001.
2003 2002 2001 - --------------------------------------------------------------------------------
Net loss attributable to common shareholders As reported $ (2,815,119) $ (3,661,344) $ (2,653,970) Stock based compensation (22,650) (77,821) (257,328) Pro forma $ (2,837,769) $ (3,739,165) $ (2,911,298) ================================================================================
Basic and diluted loss per share As reported $ (0.24) $ (0.33) $ (0.26) Pro forma (0.24) (0.34) (0.28) ================================================================================
ACCOUNTS RECEIVABLE
Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible. Management includes any accounts receivable balances that are determined to be uncollectible, along with a general reserve, in the overall allowance for doubtful accounts. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. Based on the information available to us, the Company believes no allowance for doubtful accounts as of December 31, 2003 and 2002 is necessary. However, actual write-offs may occur.
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INCOME TAXES
The Company accounts for income taxes using the "asset and 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.
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 contracts to supply two manufacturers with natural gas from the Swan Creek field through the Company's pipeline. These customers are the Company's primary customers 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.
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 does not differ from basic loss per share since the effect of all common stock equivalents is anti-dilutive. Basic and diluted loss per share are based upon 11,956,135 weighted overage common shares outstanding for the year ended December 31, 2003, 11,062,436
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weighted overage common shares outstanding for the year ended December 31, 2002, and 10,235,253 weighted overage common shares outstanding for the year ended December 31, 2001. Diluted loss per share does not consider approximately 390,278, 1,473,000, and 943,000 potential weighted average common shares for 2003, 2002, and 2001 related primarily to common stock options and convertible preferred stock and debt. 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 declared in September 2001.
FAIR VALUES OF FINANCIAL INSTRUMENTS
Fair values of cash and cash equivalents, investments and short-term debt approximate their carrying values 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.
RECENT ACCOUNTING PRONOUNCEMENTS
A reporting issue has arisen regarding the application on certain provisions of Statement of Financial Accounting Standard No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142") to companies in the extracting industries including oil and gas companies. The issue is whether SFAS 142 requires the registrants to classify the cost of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas properties owned and provide specific footnote disclosures. Historically, the Company had included the cost of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS 142 requires oil and gas companies to classify cost of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as a separate intangible asset line item on the balance sheet, the Company would be required to reclassify approximately $484,000 at December 31, 2003 and $346,000 at December 31, 2002, out of oil and gas properties and into a separate intangible asset line item. The Company's consolidated statements of net loss and cash flows would not be affected since such intangible assets would continue to be depleted and amortized for impairment in accordance with full cost accounting rules. Further, the Company does not believe the classification of the cost of mineral rights associated with extracting oil and gas as intangible assets would
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have any impact on compliance with covenants under its debt agreements.
In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company's asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its depreciation, depletion and amortization for oil and gas properties without recording a separate liability for such amounts. The Company adopted SFAS 143 beginning on January 1, 2003 and recorded a cumulative loss from adoption of this statement of approximately ($351,000). During 2003 the Company recorded $73,368 in accretion cost (using a 12% accretion factor) on the asset retirement obligation. These accretion costs are included in interest expense at December 31, 2003.
Statement of Financial Accounting Standard No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," ("SFAS 144") addresses accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 supersedes Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets" and for Long-Lived Assets to be Disposed Of. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale and expands guidance with respect to cash flow estimations. SFAS 144 became effective for the Company's fiscal year beginning January 1, 2002. The adoption of this standard did not have a material impact on the Company's financial position or results of operations.
The FASB issued Statement of Financial Accounting Standard No. 146, "Accounting for Costs Associated with Exit or Disposal Activities, ("SFAS 146") in June 2002. SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal
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activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs incurred in a Restructuring)." SFAS 146 applies to costs incurred in an "exit activity", which includes, but is not limited to, a restructuring, or a "disposal activity" covered by SFAS 144. The effect of this statement did not have a material impact on the Company.
In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34 ("FIN 45"). FIN 45 addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The disclosure requirements in FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002. The effect of this statement did not have a material impact on the Company.
During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of Variable Interest Entities" ("FIN 46"), which requires the consolidation of certain entities that are determined to be variable interest entities ("VIE's"). An entity is considered to be a VIE when either (i) the entity lacks sufficient equity to carry on its principal operations, (ii) the equity owners of the entity cannot make decisions about the entity's activities or (iii) the entity's equity neither absorbs losses or benefits from gains. The Company owns no interests in variable interest entities, and therefore this new interpretation has not affected Company's consolidated financial statements.
In May 2003, the FASB issued Statement of Financial Accounting Standard No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" ("SFAS 150"). SFAS 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity and it requires that an issuer classify a financial instrument within its scope as a liability. SFAS 150 was effective for financial instruments entered into or modified after May 31, 2003 for public companies. Restatement is not permitted. Adoption of this standard during 2003, resulted in a reclassification to a liability and restatement of the Company's amounts to estimated fair value of the Company's Series A, B and C preferred stock subject to mandatory redemption. Accordingly, for the year ended December 31, 2003, the Company recognized cumulative gain from a change in accounting
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principle of approximately $1,247,000. This cumulative gain results from the difference between the carrying amount of the preferred shares and the fair value of the shares after adoption. Accretion totaling $354,735 has been recognized as interest expense for the period from July 1, 2003 through December 31, 2003.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform with current year presentation.
3. RELATED PARTY During 2003 and 2002, the Company received TRANSACTIONS debt financing from Directors totaling $2,959,000 and $750,000 respectively, to fund operating cash flow needs and to finance continued development of the Swan Creek field. Interest incurred on this debt was approximately $206,000 and $15,000 for the years ended December 31, 2003 and 2002, respectively. See Note 7.
During 2002, the Company borrowed $110,000 from a former director. The advance was non-interest bearing and was repaid in July 2002.
During 2001, the Company repaid all principal and interest due at that time to related parties, using the proceeds from the line of credit with Bank One. Interest incurred to related parties was approximately $546,000 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.
4. OIL AND GAS The following table sets forth information PROPERTIES concerning the Company's oil and gas properties:
DECEMBER 31, 2003 2002 --------------------------------------------------------------------
Oil and gas properties, at cost $17,580,174 $17,099,753 Accumulation depreciation, depletion and amortization (4,590,731) (3,235,432) -------------------------------------------------------------------- Oil and gas properties, net $12,989,443 $13,864,321 ====================================================================
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During the years ended December 31, 2003, 2002 and 2001, the Company recorded depletion expense of approximately $1,355,000, $1, 388, 000 and $1,342,000, respectively.
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, the remaining 35 miles, was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company recorded approximately $536,000, $509,000 and $220,000; respectively in depreciation expense related to the pipeline for the years ended December 31, 2003, 2002 and 2001, respectively.
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.
6. OTHER PROPERTY Other property and equipment consisted of the AND EQUIPMENT following:
DECEMBER 31, 2003 2002 ------------------------------------------------------------------- Machinery and equipment $ 1,392,190 $1,887,190 Vehicles 490,367 675,411 Other 63,734 63,734 ------------------------------------------------------------------- 1,946,291 2,626,335
Less accumulated depreciation (1,075,561) (940,385) -------------------------------------------------------------------
Other property and equipment - net $ 870,730 $1,685,950 ===================================================================
For the year ended December 31, 2003, the Company recorded an impairment loss on equipment totaling $495,000.
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7. LONG TERM DEBT Long-term debt to unrelated entities consisted of the following:
DECEMBER 31, 2003 2002 - -----------------------------------------------------------------------------
Revolving line of credit with a bank, due November 2004. The loan agreement provides for increases or decreases to the borrowing base as changes in proved oil and gas reserves or other production levels arise. Borrowings bear interest at the bank's prime rate plus 0.25% (4.25% at December 31, 2003). Collateralized by the oil and gas properties and the related operations and revenues. See Note 1. $5,101,777 $7,501,777
Unsecured note payable to an institution with $65,000 principal payments due quarterly beginning January 1, 2000; remaining balance due October 2004; with interest payable monthly at 8% per annum. - 480,000
Convertible notes payable to five individuals; due January 2004, with interest payable quarterly at 8% per annum. Notes are convertible into common stock of the Company at a rate of $3.00 per share of common stock. 650,000 650,000
Term loan payable to a Company; due May 1, 2004. Interest is payable at 4.75%. Unsecured 297,171 - - -----------------------------------------------------------------------------
Balance carried forward $6,048,948 $8,631,777 - -----------------------------------------------------------------------------
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DECEMBER 31, 2003 2002 - -----------------------------------------------------------------------------
Balance brought forward $6,048,948 $ 8,631,777 - -----------------------------------------------------------------------------
Note payable to a financial institution, with $1,773 principal payments due monthly beginning January 7, 2002 through December 7, 2006. Interest is payable monthly commencing on January 7, 2002 at 7.5% per annum. Note is guaranteed by a major shareholder and is collateralized by certain assets of the Company. 57,004 73,335
Installment notes bearing interest at the rate of 3.9% to 11.95% per annum collateralized by vehicles and equipment with monthly payments including interest of approximately $10,000 due various periods through 2006. 242,973 412,342 - -----------------------------------------------------------------------------
Total long term debt 6,348,925 9,117,454
Less current maturities (6,127,290) (7,861,245) - -----------------------------------------------------------------------------
Long term debt, less current maturities $ 221,635 $ 1,256,209 =============================================================================
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Long-term debt to related parties consisted of the following:
DECEMBER 31, 2003 2002 - -----------------------------------------------------------------------------
Unsecured note payable to a director due January 2004, with interest payable quarterly at 8% per annum. Note is convertible into common stock of the Company at a rate of $2.88 per share of common stock. $ 500,000 $500,000
Notes payable to Directors due January 2004, with interest payable quarterly at 12% per annum. Notes are secured by the pipeline. 3,209,000 250,000 - ----------------------------------------------------------------------------- Total long term debt to related parties 3,709,000 750,000
Less current maturities (3,709,000) - - -----------------------------------------------------------------------------
Long term debt to related parties, less current maturities $ - $750,000 =============================================================================
8. COMMITMENTS The Company is a party to lawsuits in the AND CONTINGENCIES ordinary 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 on its financial statements.
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In the ordinary course of business the Company has entered into various equipment and office leases which have remaining terms ranging from one to four years. Approximate future minimum lease payments to be made under noncancellable operating leases are as follows:
Year Amount --------------------------------------------- 2004 $ 56,470 2005 56,470 --------------------------------------------- $112,940 =============================================
Office rent expense was approximately $78,830, $84,000 and $91,000 for each of the three years ended December 31, 2003, respectively.
9. CUMULATIVE The Company is authorized to create and has CONVERTIBLE issued various classes of preferred stock REDEEMABLE (Series A, Series B and Series C). Shares of PREFERRED STOCK both Series A and B of Preferred Stock are 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 for certain events. The conversion prices have been adjusted prospectively for stock dividends and splits.
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 have the right to 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 failed to pay the 3rd and 4th quarterly dividend payments of the Series A preferred stock during 2002. As a result, in February 2003, the Company and the Series A shareholders placed four new members on the Board of Directors.
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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 (March 2005), the Company is required to redeem all outstanding Series B Preferred Stock.
During 2002, the Board of Directors authorized the sale of up to 50,000 shares of Series C Preferred Stock at $100 per share. The Company issued 14,491 shares, resulting in net proceeds after commissions of $1,303,168. The Series C Preferred Stock accrues a 6% cumulative dividend on the outstanding balance, payable quarterly. These dividends are subordinate to the dividends payable to the Series A and Series B Preferred Stock holders. This stock is convertible into the Company's common stock at the average stock trading price 30 days prior to the closing of the sales of all the Series C Preferred Stock being offered or $5.00 per share, whichever is greater. The Company is required to redeem any remaining Series C Preferred Stock and any accrued and unpaid dividends in July 2006.
The Company adopted the provisions of SFAS 150 on July 1, 2003. Under SFAS 150, mandatorily redeemable preferred stock shall be reclassified at fair value to a liability. The Company has determined that each of the Series A, Series B and Series C preferred stock qualifies as shares subject to mandatory redemption, and as such, were reclassified as a liability upon adoption of SFAS 150. Accordingly, the difference between the carrying amount at the date of adoption and the fair value of the shares (discounted at 12%) was recognized as a cumulative effect of a change in accounting principle approximately $1,247,000 on July 1, 2003. The difference between the carrying amount of shares subject to mandatory redemption liability and the face value amount of preferred stock are being accreted at 12% into interest expense and the shares liability until conversion or redemption of the shares. Accretion associated with these shares subject to mandatory redemption from July 1, 2003 through December 31, 2003 was $354,735.
Additionally, upon adoption of SFAS 150, cumulative dividends stated in the agreements shall be recognized as a portion of interest cost prospectively. During the year ended December 31, 2003, the Company incurred $536,778 in dividends, of which $268,389 and
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$268,389 has been recognized as dividends on preferred stock and interest expense, respectively.
Future mandatory redemption requirements as of December 31, 2003 are as follows:
Year Amount ---------------------------------------------------------- 2003 (in arrears and past due) $ 143,395 2004 573,580 2005 3,328,580 2006 2,022,680 2007 573,580 2008 430,185 ----------------------------------------------------------
Subtotal 7,072,000 Less accretion cost included above (1,012,140) ----------------------------------------------------------
Shares subject to mandatory redemption $ 6,059,860 ==========================================================
10. ASSET RETIREMENT Effective January 1, 2003, the Company OBLIGATION implemented the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operation expense and the capitalized cost is depleted over the estimated useful life of the related asset. Additionally, SFAS No. 143 requires that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. The Company's asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date.
Using a credit-adjusted risk fee rate of 12%, an estimated useful life of wells ranging from 30-40 years, and estimated plugging and abandonment cost ranging from $5,000 per well to $10,000 per well, the Company has recorded a non-cash charge related to the cumulative effect of a change in accounting principle of $351,204 in the consolidated statements of loss. Oil and gas properties were increased by $260,191, which represents the present value of all future obligations to retire the wells at January 1, 2003, net of accumulated
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depletion on this cost through that date. A corresponding obligation totaling $611,395 has also been recorded as of January 1, 2003.
For the period ended December 31, 2003, the Company recorded accretion and depletion expenses of $73,368 associated with this liability and its corresponding asset. These expenses are included in interest expense in the consolidated statements of loss. Had the provisions of this statement been reflected in the financial statements for the year ended December 31, 2002 and 2001, asset retirement obligations of $532,269 and $477,919 would have been recorded as of January 1, 2002 and 2001, respectively.
Pro-forma net loss for the years ended December 31, 2001 and 2002 is as follows:
2002 2001 - ----------------------------------------------------------------------------- Net loss: As reported $(3,661,344) $(2,653,970) Accretion (79,126) (54,350) - ----------------------------------------------------------------------------- Pro-forma net loss $(3,740,470) $(2,708,320) =============================================================================
The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2003.
Balance, January 1, 2003: $ 611,395 Accretion expense through December 31, 2003 73,368 Liabilities Settled (16,207) - ------------------------------------------------------------------------------
Balance, December 31, 2003 $ 668,556 ==============================================================================
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, fully vest after two years of employment with the Company, 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
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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 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 an 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 2003, 2002 and 2001 is summarized below:
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The share information disclosed above has been adjusted to reflect a 5% stock dividend declared during 2001.
The following table summarizes information about stock options outstanding at December 31, 2003:
OPTIONS OPTIONS OUTSTANDING EXERCISABLE ---------------------------------------------------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE REMAINING EXERCISE CONTRACTUAL PRICE SHARES LIFE (YEARS) SHARES ---------------------------------------------------------------- $ 0.50 342,000 2.33 342,000
$ 2.86 109,590 1.67 109,590
$12.70 10,000 0.67 10,000 -------------- --------------
Total 461,590 461,590 ================================================================
The weighted average fair value per share of options granted during 2003, 2002 and 2001 is $0.16, $1.45 and $3.62, respectively, calculated using the Black-Scholes Option-Pricing model.
No compensation expense related to stock options was recognized in 2003, 2002 or 2001.
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 2003, 2002 and 2001: Expected volatility of 40% for 2003, 74.2% for 2002 and 50% for 2001; a risk free interest rate of 3.67% in 2003, 3.67% in 2002 and 3.67% in 2001; and an expected option life of 3 years for 2003, 2002 and 2001.
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12. INCOME TAXES The Company has no taxable income during the three year period ended December 31, 2003.
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:
DECEMBER 31, 2003 2002 2001 - -------------------------------------------------------------------------------- Statutory rate 34% 34% 34% Tax benefit at statutory rate $ (866,000) $ (1,073,000) $ (769,000) State income tax benefit (152,000) (189,000) (136,000) Other - - Increase in deferred tax asset valuation allowance 1,018,000 1,262,000 905,000 - --------------------------------------------------------------------------------
Total income tax provision $ - $ - $ - ================================================================================
DECEMBER 31, 2003 2002 2001 - --------------------------------------------------------------------------------
Net operating loss carryforward $8,157,000 $ 7,139,000 $ 5,877,000 Capital loss carryforward 263,000 263,000 263,000 - --------------------------------------------------------------------------------
8,420,000 7,402,000 6,140,000
Valuation allowance (8,420,000) (7,402,000) (6,140,000) - --------------------------------------------------------------------------------
Net deferred taxes $ - $ - $ - ================================================================================
The Company recorded a valuation allowance at December 31, 2003, 2002 and 2001 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. Potential future reversal of the portion of the valuation allowance relative to deferred tax asset resulting from the exercise of stock options will be recorded as additional paid in capital realized
As of December 31, 2003, the Company had net operating loss carryforwards of approximately $13,700,000 which will expire between 2010 and 2023 if not utilized.
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13. SUPPLEMENTAL CASH The Company paid approximately $634,635, FLOW INFORMATION $571,000 and $853,500 for interest in 2003, 2002 and 2001, respectively. The Company capitalized approximately $148,000 of interest in 2001. No interest was capitalized in 2003 or 2002. No income taxes were paid in 2003, 2002, or 2001.
14. RIGHTS OFFERING On October 17, 2003, the Company filed a Registration Statement on Form S-1 with the Securities and Exchange Commission ("SEC"). On February 13, 2004, the SEC deemed the Registration Statement on Form S-1 effective.
The Rights Offering was a distribution to the holders of the Company's common stock outstanding at the record date, February 27, 2004, at no charge, of nontransferable subscription rights at the rate of one right to purchase three shares of the Company's common stock for each share of common stock owned at the subscription price of $0.75 in the aggregate, or $0.25 per each share purchased.
Each subscription right in addition to the right to purchase three shares of common stock carried with it an over-subscription privilege. The over-subscription privilege provided stockholders that exercise all of their basic subscription privileges with the opportunity to purchase those shares that were not purchased by other stockholders through the exercise of their basic subscription privileges at the same subscription price per share. In no event could any subscriber purchase shares of the Company's common stock in the offering that, when aggregated with all of the shares of the Company's common stock otherwise owned by the subscriber and his, her or its affiliates, would immediately following the closing represent more than 50% of the Company's issued and outstanding shares.
The net proceeds of the Rights Offering will be used initially to pay non-bank indebtedness in the aggregate amount of approximately $6 million (including up to $3,850,000 in principal amount plus accrued interest owed by the Company to Dolphin Offshore Partners, L.P., the general partner of which is Peter E. Salas a director of the Company), with the balance of the net proceeds to be used to repay bank indebtedness and/or for working capital purposes, including the drilling of additional wells. At December 31, 2003, the Company incurred offering costs $223,003, which are reflected in the consolidated balance sheet as an asset. This asset will be offset against gross proceeds, when received by the Company.
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At the time the Rights Offering closed on March 18, 2004 all 36.3 million shares offered had been subscribed for and, as a result, the Company raised approximately $9.1 million. The total number of shares subscribed actually exceeded the 36.3 million shares available for issuance under the offering. Consequently, all shares subscribed for under the basic privilege were issued and the number shares issued under the over subscription privilege was proportionately reduced to equal the number of remaining shares. The allocation and issuance of the oversubscribed shares was made by Mellon Investor Services, the Company's subscription agent who also returned payments for those oversubsubcribed shares that were not available.
As called for in the Rights Offering, 7,029,604 rights were exercised pursuant to the basic subscription privilege, resulting in the purchase of 21,088,812 shares at $0.25 per share for gross proceeds to the Company of $5,272,203 resulting from the basic subscription privilege. A total of 15,211,118 shares were purchased pursuant to the oversubscription privilege, resulting in additional gross proceeds to the Company of $3,802,797. Of the shares purchased pursuant to the Rights Offering 14,966,344 shares were purchased by Directors, Officers and owners of more than ten percent (10%) of the Company's outstanding common stock.
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15. QUARTERLY DATA AND The following table sets forth, for the SHARE INFORMATION fiscal periods indicated selected (UNAUDITED) consolidated financial data.
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(a) 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.
(b) Amounts disclosed above for the third quarter of 2003 differ from those previously filed with the SEC as a result of adopting SFAS 150 after September 30, 2003. Management will amend the September 30, 2003 SEC Form 10-Q filing during 2004.
(c) During the fourth quarter of 2003, the Company recognized an impairment loss on equipment totaling $495,000.
16. SUPPLEMENTAL OIL AND Information with respect to the Company's oil GAS INFORMATION and 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, 2003, 2002 and 2001.
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, 2003, 2002 and 2001:
2003 2002 2001 - -----------------------------------------------------------------------------
Property acquisition Proved $ - $ - $ - Unproved - - - Less - proceeds from sales of properties - (100,000) (750,000) Development costs 480,421 2,082,529 5,571,883 - -----------------------------------------------------------------------------
$480,421 $1,982,529 $4,821,883 =============================================================================
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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:
December 31, 2003 2002 2001 ------------------------------------------------------------------------------
Revenues $ 6,040,872 $ 5,437,723 $ 6,656,758 Production costs and taxes (3,412,201) (3,094,731) (2,951,746) Depreciation, depletion and amortization (1,268,470) (1,388,138) (1,342,000) ------------------------------------------------------------------------------
Income from oil and gas producing activities $ (1,360,201) $ 954,854 $ 2,363,012 ------------------------------------------------------------------------------
In the presentation above, no deduction has been made for indirect 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, 2003, 2002 and 2001 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.
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OIL (BBLS) GAS (MCF) - -----------------------------------------------------------------------------
Proved reserves:
Balance, January 1, 2001 1,814,905 47,539,871 Discoveries and extensions 62,254 4,915,431 Revisions of previous estimates (672,443) (25,263,634) Production (148,041) (1,311,466) Balance, January 1, 2002 1,056,675 25,880,202 Discoveries and extensions 34,968 937,000 Revisions of previous estimates 542,229 786,430 Production (157,973) (1,004,899) - -----------------------------------------------------------------------------
Balance, December 31, 2002 1,475,899 26,598,733 Discoveries and extensions 0 0 Revisions of previous estimates 42,478 (11,633,157) Production (147,243) (620,873) - ----------------------------------------------------------------------------- Proved reserves at, December 31, 2003 1,371,134 14,344,703 Proved developed producing reserves at, December 31, 2003 1,059,038 5,167,832 ============================================================================= Proved developed producing reserves at, December 31, 2002 1,108,293 6,592,711 ============================================================================= Proved developed producing reserves at, December 31, 2001 767,126 7,157,183 =============================================================================
Of the Company's total proved reserves as of December 31, 2003 and 2002 and 2001, approximately 51%, 37% and 36%, respectively, were classified as proved developed producing, 14%, 19% and 26%, respectively, were classified as proved developed non-producing and 35%, 44% and 37%, respectively, were classified as proved undeveloped. All of the Company's reserves are located in the continental United States.
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:
AMOUNTS IN THOUSANDS --------------------------------------------- December 31, 2003 2002 2001 - --------------------------------------------------------------------------------
Future cash inflows $ 109,102 $152,180 $ 78,296 Future production costs and taxes (48,761) (41,870) (26,083) Future development costs (5,957) (11,348) (6,384) Future income tax expenses - - - - --------------------------------------------------------------------------------
Net future cash flows 54,384 98,962 45,829
Discount at 10% for timing of cash flows (28,021) (52,314) (24,095) - --------------------------------------------------------------------------------
Discounted future net cash flows from proved reserves $ 26,363 $ 46,648 $ 21,734 ================================================================================
The following unaudited table sets forth the changes in the standardized measure of discounted future net cash flows from proved reserves during 2003, 2002 and 2001:
AMOUNTS IN THOUSANDS ----------------------------------------------- 2003 2002 2001 - --------------------------------------------------------------------------------
BALANCE, beginning of year $ 46,648 $ 21,734 $ 235,743 Sales, net of production costs and taxes (2,884) (2,343) (3,705) Discoveries and extensions - 1,686 4,167 Changes in prices and production costs (9,040) 20,586 (299,527) Revisions of quantity estimates (13,988) 6,120 (33,449) Development costs incurred - - Interest factor - accretion of discount 4,665 2,173 32,198 Net change in income taxes - - 86,237 Changes in future development costs 5,391 (4,860) 2,666 Changes in production rates and other (4,429) 1,552 (2,596) - -------------------------------------------------------------------------------- BALANCE, end of year $ 26,363 $ 46,648 $ 21,734 ================================================================================
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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, 2003, 2002 and 2001 were $29.72, $27.25 and $17.03 per barrel of oil and $4.76, $4.01 and $2.33 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. The estimates of reserve values include estimated future development costs that the company does not currently have the ability to fund. If the company is unable to obtain additional funds, it may not be able to develop its oil and natural gas properties as estimated in its December 31, 2003 reserve report.
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.