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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
REPORT ON FORM 10-K
(Mark one)
/X/ Annual Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended DECEMBER 31, 2001 or
/ / Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from ______________ to
______________.
Commission File No. 0-20975
TENGASCO, INC.
(NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TENNESSEE 87-0267438
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
603 MAIN AVENUE, KNOXVILLE, TENNESSEE 37902
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (865) 523-1124.
Securities registered pursuant to Section 12(b) of the Act: NONE.
Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, $.001
PAR VALUE PER SHARE.
Indicate by checkmark whether the registrant (1) filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days: Yes /X/ No / /
Indicate by checkmark if disclosure of delinquent filers in response to
Item 405 of Regulation SK is not contained in this form and no disclosure will
be contained, to the best of the registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [ ]
State issuer's revenues for its most recent fiscal year: $6,953,089
State the aggregate market value of the voting stock held by nonaffiliates
(based on the closing price on March 1, 2002 of $6.38): $43,111,759.
State the number of shares outstanding of the registrant's $.001 par value
common stock as of the close of business on the latest practicable date (March
1, 2002): 10,656,401
Documents Incorporated By Reference: None.
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TABLE OF CONTENTS
Page
PART I
Item 1. Business ................................................ 1
Item 2. Description Of Property ................................. 21
Item 3. Legal Proceedings ....................................... 28
Item 4. Submission of Matters to a Vote of Security Holders ..... 31
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters ..................................... 32
Item 6. Selected Financial Data ................................. 34
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation ...................... 35
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk ............................................. 44
Item 8. Financial Statements and Supplementary Data ............. 45
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure ..................... 45
PART III
Item 10. Directors and Executive Officers of the Registrant ...... 46
Item 11. Executive Compensation .................................. 52
Item 12. Security Ownership of Certain Beneficial Owners
and Management .......................................... 55
Item 13. Certain Relationships and Related Transactions .......... 59
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K ............................................. 60
SIGNATURES .................................................................. 66
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FORWARD LOOKING STATEMENTS
The information contained in this Report, in certain instances,
includes forward-looking statements. When used in this document, the words
budget, budgeted, anticipate, expects, estimates, believes, goals or projects
and similar expressions are intended to identify forward-looking statements. It
is important to note that the Company's actual results could differ materially
from those projected by such forward-looking statements. Important factors that
could cause actual results to differ materially from those projected in the
forward-looking statements include, but are not limited to, the following:
production variances from expectations, volatility of oil and gas prices, the
need to develop and replace reserves, the substantial capital expenditures
required for construction of pipelines and the drilling of wells and the related
need to fund such capital requirements through commercial banks and/or public
securities markets, environmental risks, drilling and operating risks, risks
related to exploration and development drilling, the uncertainty inherent in
estimating future oil and gas production or reserves, uncertainty inherent in
litigation, competition, government regulation, and the ability of the Company
to implement its business strategy, including risks inherent in integrating
acquisition operations into the Company's operations.
PART I
ITEM 1. BUSINESS.
OVERVIEW
The Company is in the business of exploring for, producing and
transporting oil and natural gas in Tennessee and Kansas. The Company leases
producing and non-producing properties with a view toward exploration and
development. Emphasis is also placed on pipeline and other infrastructure
facilities to provide transportation, processing and tieback services. The
Company utilizes state-of-the-art seismic technology to maximize the recovery of
reserves. The Company's activities in the oil and gas business commenced in May
1995 with the acquisition of oil and gas leases in Tennessee.
Since 1995 the Company has acquired oil and gas leases on a total of
approximately 60,000 acres, located in Hancock, Claiborne, Knox, Jefferson and
Union Counties in Tennessee.
Effective December 31, 1997, the Company acquired from AFG Energy,
Inc. ("AFG"), a private company, approximately 32,000 acres of leases in the
vicinity of Hays, Kansas (the "Kansas Properties"). Included in the acquisition
which closed on March 5, 1998 were 273 wells, including 208 working wells, of
which 149 are producing oil wells and 59 are producing
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gas wells, a related 50 mile pipeline and gathering system, 3 compressors and 11
vehicles. The total purchase price of these assets was approximately $5.5
million, which consisted of $3 million in cash and seller financing of $2.5
million. The seller financing portion of the purchase price was refinanced by
Arvest United Bank of Oklahoma City, Oklahoma as evidenced by a note dated
November 23, 1999 in the amount of $1,883,650 to be paid in monthly installments
of principal and interest over a three year period. This obligation was
subsequently satisfied from the proceeds of a line of credit received by the
Company from Bank One, N.A. of Houston, Texas ("Bank One"). See, "Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation."
The Kansas Properties are currently producing approximately one
million cubic feet of natural gas and 400 barrels of oil per day. Net revenues
from the Kansas Properties at the present time is approximately $315,000 per
month.
To date, the Company has been drilling primarily on a portion of its
Tennessee leases, the 50,500 acre Swan Creek Field in Hancock County (the "Swan
Creek Field or Leases") focused within the Knox formation, one of the geologic
formations in the Field. It shortly intends to commence drilling in one of the
other geologic formations in the Swan Creek Field. In 2001, the Company had 29
producing gas wells and 6 producing oil wells.
On November 18, 1999, the Company entered into a contract with
Eastman Chemical Company ("Eastman"), in Kingsport, Tennessee, pursuant to which
Eastman agreed to purchase a minimum of the lesser of 80% of its requirements or
10,000 MMBtu's (MMBTU MEANS ONE MILLION BRITISH THERMAL UNITS) of gas per day,
for twenty years.
On March 30, 2001, the Company entered into a contract with BAE
Systems ("BAE"), the operator of the Holston Army Ammunition Plant in Kingsport,
Tennessee, pursuant to which BAE agreed to purchase all its gas requirements up
to a maximum of 5,000 MMBtu's per day of gas for twenty years.
On March 8, 2001, the Company's wholly owned subsidiary, Tengasco
Pipeline Corporation, completed a 65 mile intrastate pipeline from the Swan
Creek Field to Kingsport, Tennessee at a cost to date of approximately $15.3
million through which it delivers its gas to Eastman, BAE and other customers in
East Tennessee.
Delivery of gas to BAE commenced on April 4, 2001 and to Eastman on
May 24, 2001. Commencing in June, 2001, the Company was producing approximately
5 million cubic feet of gas ("MMcf"are units of one million cubic feet of gas)
per day from its existing wells in the Swan Creek Field. Based upon the
estimated reserves contained in a reserve analysis report as of December 31,
2001 provided to the Company by Ryder Scott Company, L.P. and the initial
production output of the existing wells, the Company anticipated that from
existing wells and new wells to be completed during 2001, it would be able to
produce and sell approximately 10 MMcf of gas per day to Eastman and BAE by the
end of 2001. However, in view of the lack of production history from the wells
or other wells in the area, various technical difficulties and
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substantial problems with higher than expected fluids in the wells, led to
significant reductions in the amount of gas produced and the Company was unable
to meet these projected goals. At present, the Company is producing
approximately 3MMcf of gas per day from its Swan Creek Field, a reduction from
the average of 4-5 MMcf produced in the beginning of the second half of 2001.
This reduction is the result of the problems discussed above; the fact that it
was necessary to shut down many of the wells while work to resolve the problems
was being done; and, the fact that the Company has temporarily stopped drilling
any new wells in the Swan Creek Field due to the necessity of devoting its
efforts to the task of improving the production from the existing wells.
At present, work has been completed on 11 wells to reduce the
adverse effects of the fluid problems on the production of gas. Additional work
to eliminate the fluid problems from the wells, and, in some cases, to drill new
wells to replace troubled wells is ongoing, and the Company expects that
production to increase substantially from the Swan Creek Field by the end of
2002. The Company's efforts will be aided significantly by geological
information of the Knox formation derived from its experience with the wells
already drilled. The Company has now been able to assimilate a detailed
description and location of the primary producing geological structure. This now
allows for enhanced placement and relocation of some wells into the more
productive part of the Knox formation. This approach has been similar to a 3D
seismic acquisition and evaluation without the high cost associated with such a
procedure. As a result, although no assurances can be given, the Company
believes that the amount of fluids in any of the new wells to be drilled in the
Swan Creek Field will be significantly reduced. The Company hopes to commence
drilling of new wells in the Swan Creek Field shortly. The Company will also
continue to conduct exploration and production activities to produce increased
quantities of crude oil and natural gas. See, "Item 7 Management's Discussion
and Analysis of Financial Condition and Results of Operation - Liquidity and
Capital Resources" for discussion regarding funding for development activities.
HISTORY OF THE COMPANY
The Company was initially organized under the laws of the State of
Utah on April 18, 1916, under the name "Gold Deposit Mining & Milling Company."
The Company subsequently changed its name to Onasco Companies, Inc. The Company
was formed for the purpose of mining, reducing and smelting mineral ores.
On November 10, 1972, the Company conveyed to an unaffiliated entity
substantially all of the Company's assets and the Company ceased all business
operations.
From approximately 1983 to 1991, the operations of the Company were
limited to seeking out the acquisition of assets, property or businesses.
At a special meeting of stockholders held on April 28, 1995, the
Company's stockholders voted:
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(i) to approve the execution of an agreement (the "Purchase
Agreement") pursuant to which the Company would acquire certain oil and gas
leases, equipment, securities and vehicles owned by Industrial Resources
Corporation ("IRC")(1), a Kentucky corporation, in consideration of the issuance
of 4,000,000 post-split (as described below) "unregistered" and "restricted"
shares of the Company's common stock and a $450,000 8% promissory note payable
to IRC. The promissory note was converted into 83,799 shares of the Company's
common stock in December 1995;
(ii) to amend the Articles of Incorporation of the Company to
effect a reverse split of the Company's outstanding $0.001 par value common
stock on a basis of one share for two, retaining the par value at $0.001 per
share, with appropriate adjustments being made in the additional paid-in capital
and stated capital accounts of the Company;
(iii) to change the name of the Company from "Onasco Companies,
Inc." to "Tengasco, Inc."; and
(iv) to change the domicile of the Company from the State of Utah
to the State of Tennessee by merging the Company into Tengasco, Inc., a
Tennessee corporation, formed by the Company solely for this purpose.
The Purchase Agreement was duly executed by the Company and IRC,
effective May 2, 1995. The reverse split, name change and change of domicile
became effective on May 4, 1995, the date on which duly executed Articles of
Merger effecting these changes were filed with the Secretary of State of the
State of Tennessee; a certified copy of the Articles of Merger from the State of
Tennessee was filed with the Department of Commerce of the State of Utah on May
5, 1995. Unless otherwise noted, all subsequent computations herein
retroactively reflect this one for two reverse split.
During 1996, the Company formed Tengasco Pipeline Corporation, a
wholly-owned subsidiary, to manage the construction and operation of its
pipeline, as well as other pipelines planned for the future.
GENERAL
1. THE SWAN CREEK FIELD
Amoco Production Company ("AMOCO") during the late 1970's and early
1980's, after extensive geological and seismic studies, acquired approximately
50,500 acres of oil and gas leases in the Eastern Overthrust in the Appalachian
Basin, an area now referred to as the Swan
- ----------
(1) Malcolm E. Ratliff, the Company's Chief Executive Officer and Chairman of
the Board of Directors, is the the sole shareholder of IRC.
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Creek Field.
In 1982 AMOCO successfully drilled two significant natural gas
discovery wells in the Swan Creek Field to the Knox Formation at approximately
5,000 feet of total depth. These wells, once completed, had a high pressure and
volume of deliverability of natural gas; however, in the mid-1980's a
substantial decline in worldwide oil and gas prices occurred and the high cost
of constructing a necessary 23 mile pipeline across three rugged mountain ranges
and crossing the environmentally protected Clinch River from Sneedville to the
closest market in Rogersville, Tennessee was cost prohibitive.
In 1987, AMOCO farmed out its leases to Eastern American Energy
Company which held the leases until July 1995. The Company became aware of a law
adopted by the Tennessee legislature which enabled the Company to lease all of
AMOCO's prior acreage. The Company filed for a declaratory judgment as to its
right to lease AMOCO's prior acreage. The Company was ultimately successful in
winning all right, title and interest in all of AMOCO's prior leases in a
precedent setting Supreme Court case.
In July 1995 after completion of the Purchase Agreement with IRC,
the Company acquired the Swan Creek Leases. These leases provide for a landowner
royalty of 12.5%.
In July 1998 the Company completed the first phase ("Phase I") of
its pipeline in the Swan Creek Field, a 30 mile pipeline made of 6 and 8 inch
steel pipe running from the Swan Creek Field into the main city gate of
Rogersville, Tennessee. With the assistance of the Tennessee Valley Authority
("TVA"), the Company was successful in utilizing TVA's right-of-way along its
main power line grid from the Swan Creek Field to the Hawkins County Gas Utility
District located in Rogersville. The cost of constructing Phase I of the
pipeline was approximately $4,200,000.
Having completed Phase I of its pipeline, in July 1998 the Company
began selling gas to Hawkins County Utility District which services residential,
municipal and industrial customers in the Hawkins County area, pursuant to a
written contract entered into on September 26, 1996. During the period from
August 1998 through December 31, 1998 the Company delivered 46,776 cubic feet of
gas to Hawkins County Utility District.
During the period from January 1, 1999 through March 23, 1999
Hawkins County Utility District took only 477 Mcf of gas ("Mcf" are units of one
thousand cubic feet of gas) from the Company. Although Hawkins County Utility
District could take gas in greater quantities, it declined to do so. Pursuant to
its original contract, it was not obligated to purchase any specific amount of
gas. The contract with the Hawkins County Utility District was renegotiated and
an Amendment Agreement was entered into on October 19, 1999 whereby the Hawkins
County Utility District committed to take a minimum of 500 Mcf and a maximum of
4,000 Mcf of gas per day with an option to purchase up to an additional 3,000
MCF per day. Pursuant to this Agreement, the Hawkins County Utility District
began purchasing gas from the Company as of November 2, 1999. Hawkins County has
purchased relatively small quantities of gas which the
5
Company was able to blend from certain wells to provide gas which contains less
than 4% nitrogen. Hawkins County's position is that it is not required to
purchase contract volumes unless the nitrogen content is less than 4%, although
the Company has demonstrated that its gas, with a nitrogen content of
approximately 4.5% is interchangeable with 4% gas. Since November 2, 1999,
Hawkins County Utility District has purchased 3,910 Mcf of gas. The Company
stands ready to deliver additional quantities of gas, but there can be no
assurances that Hawkins County will purchase additional quantities of gas.
On November 18, 1999, the Company entered into an agreement with
Eastman Chemical Company ("Eastman") which provides that the Company will
deliver daily to Eastman's plant in Kingsport a minimum of the lesser of (i)
5,000 MMBtu's (MMBtu means one million British thermal units which is the
equivalent of approximately one thousand cubic feet of gas) or (ii) forty
percent (40%) of the natural gas requirements of Eastman's plant and a maximum
of 15,000 MMBtu's per day. Under the terms of the agreement, the Company has the
option to install facilities to treat the delivered gas so that the total
non-hydrocarbon content of the delivered gas is not greater than two percent
(2%). This will allow the gas to be used in certain processes in the Eastman
plant requiring low levels of non-hydrocarbons. If the Company elects to perform
this option by installing additional facilities, the minimum daily amount of gas
to be purchased by Eastman from the Company will increase to the lesser of
(i)10,000 MMBtu's or (ii) eighty percent (80%) of the natural gas requirements
of Eastman's chemical plant.
On March 27, 2000, the Company and Eastman signed an amendment to
the agreement permitting the Company a further option with respect to the
allowable level of non-hydrocarbons in the delivered gas. This amendment gives
the Company the further option to tender gas without treatment, at a minimum
volume of 10,000 MMBtu's per day, in consideration of which the Company agrees
to accept a price reduction of five cents per MMBtu for the volumes per day
between 5,000 and 10,000 MMBtu's per day under the pricing structure in place
under the original agreement. To date, none of the gas sold by the Company to
Eastman exceeds the allowable level of non-hydrocarbons permitted under the
agreement and does not require treatment.
Under the agreement as amended March 27, 2000, Eastman agreed to pay
the Company the index price plus $0.10 for all natural gas quantities up to
5,000 MMBtu's delivered per day, the index price plus $0.05 for all quantities
in excess of 5,000 MMBtu's per day and the index price for all quantities in
excess of 15,000 MMBtu's per day. The index price means the price per MMBtu
published in McGraw-Hill's INSIDE F.E.R.C Gas Market Report equal to the Henry
Hub price index as shown in the table labeled Market Center Spot Gas Prices.
During the six months ended February 28, 2002, the index price has ranged from a
high of $3.19 per MMBtu in August 2001 to a low of $1.86 in October 2001.
The agreement with Eastman is for a term of twenty years and will be
automatically extended, if the parties agree, for successive terms of one year.
The initial term of the agreement was to commence upon the Company's completion
of construction of Phase II of its pipeline and connection to Eastman's
facilities and once commercial operation of that facility
6
was approved. Pursuant to its agreement with Eastman, completion of construction
of Phase II of the pipeline was originally to be made by December 31, 2000.
However, Eastman subsequently agreed to extend the completion date of
construction to March 31, 2001.
Because the Company is required to enter into hedging agreements in
fiscal 2002 pursuant to its credit facility agreement with Bank One, this may
have an effect on the revenues it receives from actual sales of gas during that
period. Under the credit facility agreement with Bank One, the volume made
subject to the initial hedging agreement was not to be based on the Company's
actual sales volumes. Under its present hedging agreement with Bank One which
terminates on July 31, 2002, if the index price on a theoretical volume of 3,500
MMBtu per day of natural gas ranges between $2.50 and $3.01per MMBtu the
Company's hedging will have no effect. However, if the index price falls below
$2.50 per MMBtu the Company s hedging agreement will result in it actually
receiving from Bank One under the hedge agreement, the difference between the
actual price and $2.50 for the hedged volume of natural gas. If the index price
rises above $3.01 per MMBtu the Company's hedging agreement will result in it
actually paying to Bank One under the hedge agreement, the difference per MMBtu
between the actual price and $3.01 for the hedged volume of natural gas.
On January 25, 2000, the Company's wholly owned subsidiary, Tengasco
Pipeline Corporation ("Tengasco Pipeline"), signed a franchise agreement to
install and operate new natural gas utility services to residential, commercial
and industrial users in Hancock County, Tennessee for the Powell Valley Utility
District. The Powell Valley District has no existing natural gas facilities and
the system to be installed by Tengasco Pipeline will initially extend to schools
and small customers, and will be gradually expanded over time to serve as many
of the 6,900 residents of the County as is economically feasible. Tengasco
Pipeline will purchase gas from the Company on behalf of the District and it
will be resold at an average retail price of about $8.00 Mcf. Under the
franchise agreement, which has an initial term of ten years and may be renewed
for an additional ten years, Tengasco Pipeline will receive 95% of the gross
proceeds of the sale of gas for its services under the agreement. In June, 2000,
Tengasco Pipeline began installation of the necessary facilities to begin to
serve up to 1,500 residential and industrial consumers in the City of
Sneedville, county seat of Hancock County. The Company's existing eight inch
main line from its Swan Creek Field passes through the city limits of
Sneedville. A one-half mile of interconnecting pipeline from the Company's
existing pipeline was installed, as well as an additional four miles of pipeline
as the initial phase of the distribution system. The construction was completed
and delivery of initial volumes of gas into the system from the Swan Creek field
occurred on December 27, 2000. The cost of construction of these facilities was
approximately $133,000. Upon enactment of initial rate schedules by the Powell
Valley Utility District, initial sales began in January, 2001 to a small number
of residential and small commercial customers. Tengasco Pipeline has contracted
with the City of Sneedville to conduct billing and installation activities in
connection with the day to day operation of this system. On March 11, 2002, the
Company began delivering gas to its first commercial customer in a new
industrial park in Sneedville, Kiefer Built, Inc, an Iowa based manufacturer of
livestock and industrial trailers. The Company hopes to be able to supply gas to
other customers who may move into that industrial park. At this time, no gas
sales agreements for large volume or base load sales have been signed and there
can be no assurances that such agreements will be signed and if
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signed, it is not possible to predict when such sales may begin or what the
overall volumes of gas sold may be.
On March 17, 2000, the Company announced that it had entered into an
agreement with the University of Tennessee-Knoxville ("UTK") related to its
hydrocarbon exploration activities in eastern Tennessee. Two UTK geological
scientists, Professor Robert D. Hatcher, Jr., a University of Tennessee/Oak
Ridge National Laboratory Distinguished Scientist in structural and Appalachian
geology and now a Director of the Company, and Dr. Richard T. Williams, Ph. D.,
Associate Professor in geophysics, provide the Company with assistance in
interpreting the structure of the Swan Creek Field and geophysical data from
that field. New seismic data will permit better subsurface imaging and more
exact determination of the size of the Swan Creek Field.
A major outgrowth of the Company's relationship with UTK is a new
graduate fellowship, called the Tengasco Fellowship, to be awarded in UTK's
Department of Geological Sciences to an outstanding graduate student interested
in pursuing a career in the petroleum industry. The fellowship will provide a
living allowance and tuition for the student. Two UTK PH. D. students receiving
financial support from the Company have already provided computer generated 3-D
images of the Swan Creek Field. These images have helped outline the subsurface
shape of the hydrocarbon producing zone to allow the Company to better
understand where additional production might be located.
The Company and the University of Tennessee have signed a Memorandum
of Agreement concerning cooperation between them in the use of vibreosis seismic
equipment, primarily a large vibrator truck, owned by the University that is to
be used in the Company's exploration program. Under the agreement, the Company
is entitled to use the equipment in exchange for performing required routine
expert maintenance and upkeep on the University's equipment, the cost of which
exceeds the University's available resources. The University-owned truck is
identical to two trucks owned by the Company and used in its seismic exploration
program.
In April 2000, Tengasco Pipeline commenced construction of Phase II
of the Company's pipeline. When the pipeline was completed on March 8, 2001, an
additional 35 miles of pipeline of 8 and 12 inch pipe had been laid at a cost to
date of approximately $11.1 million extending the Company's pipeline from a
point near the terminus of Phase I and connecting to an existing pipeline and
meter station at Eastman's chemical plant. The completed pipeline extends 65
miles from the Company's Swan Creek Field to Kingsport, Tennessee.
On March 30, 2001, the Company signed a contract to supply natural
gas to BAE SYSTEMS Ordnance Systems Inc. ("BAE"), operator of the Holston Army
Ammunition Plant in Kingsport, Tennessee for a period of twenty years. Natural
gas is used at the Holston Army ammunition facility to fire boilers and furnaces
for steam production and process operations utilized in the manufacture of
explosives by BAE for the United States military. Under the agreement, BAE's
daily purchases of natural gas will be between 1.8 million and 5 million cubic
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feet, and volume could increase significantly over the life of the agreement as
BAE conducts additional operations at the Holston facility. The contract calls
for a price based on the monthly published index price for spot sales of gas at
the Henry Hub plus five cents per MMBtu in the same manner as the price is
calculated in the contract between the Company and Eastman. The contract with
BAE provides that the Company's obligation to sell gas to BAE is subject to
availability of gas after the Company satisfies its obligation in accordance
with Eastman's needs up to 15 MMcf per day.
The Company will be the sole supplier of natural gas to BAE under
this agreement and the Company has the only gas pipeline located on the grounds
of the 6,000-acre Holston facility. A portion of the Holston facility is being
developed by BAE as the new Holston Business and Technology Park which will
serve as a location for additional commercial and industrial customers. The
Company's presence at the Holston Business and Technology Park will provide the
availability of gas service to other customers and is considered by BAE to be an
important factor in the development of the Park, as well as the source of
potential new customers for the Company. Although the Company's gas production
from its Swan Creek Field has not been sufficient to supply the quantity of gas
that Eastman has been willing to purchase under its agreement with the Company,
Eastman has not, to date, objected to sales of gas by the Company to BAE and
others.
During 2001, the Company had 29 producing gas wells and six
producing oil wells in the Swan Creek Field. Miller Petroleum, Inc. and others
had a participating interest in twelve of these wells. See, "Item 2 -
Description of Property - Property Location, Facilities, Size and Nature of
Ownership." In total, the Company has completed 44 wells and two wells are in
the process of being completed in the Swan Creek Field. Of the completed wells,
nine are shut-in or currently not producing because these wells are either not
presently producing commercial quantities of hydrocarbons, or are awaiting
workover or tie-in to the Company's pipeline. However, certain of these wells
may not be tied-in to the Company's pipeline since the expense of connection
over rough terrain may not be justified in view of the expected volumes to be
produced. The majority of these gas wells were drilled prior to the completion
of the pipeline system so only test data was available prior to full production.
The Company began delivering gas through its pipeline to BAE on
April 4, 2001 and to Eastman on May 24, 2001. June's daily production was
4,936.2 Mcf and July's daily production average increased to 5,497 Mcf per day
and the Company anticipated that it would reach its goal of delivering 10MMcf
per day to Eastman and BAE by the end of 2001. However, the Company was unable
to attain that production target due to the in-flow of substantially more fluids
in the existing wells than expected. These fluids entered the wells from the
boreholes. The fluids obstructed and significantly reduced the flow of gas from
the existing wells and required the Company to perform substantial additional
work and repairs to increase the production from existing wells. First, it was
necessary to install a drip tank system to eliminate the fluids in the pipeline.
Next, the Company had to install mechanical devices in many of the existing
wells to reduce the fluid problems. As a result of this repair work, many of the
existing wells had to be shut down while the repairs were made. In addition, the
Company temporarily ceased drilling new
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wells in order to concentrate its efforts on the repairs. These fluid entry
problems along with natural production declines and suspension of drilling
activity have led to production totals lower than anticipated. The decline
appears to be stabilizing and leveling off at approximately 3MMcf of gas per day
from the Swan Creek Field.
To date, two types of mechanical devices, pump jacks and gas lifts
have been installed in 11 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 devices have had a variety of effects on
production totals of existing wells. On some individual wells production has
more than doubled, while on others, although production totals have not
increased, the monthly average production volume has become constant and more
predictable. Some of the decline in production from existing wells is also
related to natural fracture production and the associated decline to steadier
flow rates from such a two-part system. The natural storage system for the
formation in the Swan Creek Field to which the Company's existing wells have
been drilled and from which gas is currently being produced, i.e, the Knox
Formation, has both primary and secondary porosity distributed throughout the
dolomite rock that makes up this complex formation. All types of gas wells
experience some type of decline as production takes place. While the natural
fractures enhance production cumulative overall and contribute to longevity, the
initial production declines can be significant. These natural declines were
expected and do not diminish either the shut in pressure or the Company's actual
reserves in the Swan Creek Field. They do, however, suggest the production rates
from some of the smaller wells will be slower, but production will last longer
than expected. The Company is currently considering a plan to customize an
acidizing program for some of its more productive existing wells which might
lead to more rapid recovery and accelerate production. Such a program would be
targeted to 3 or 4 of the existing wells. It is unknown at this time what the
impact such a program might have. The Company also plans to install additional
gas lifts in 5 more of the existing wells and in the other existing wells as
needed, although not all wells have fluid problems.
In addition to the work on existing wells, the Company intends to
drill several new wells within the Knox formation. Because the Knox formation
has been defined by the accumulation of data from the previously drilled wells,
new locations and new wells are expected to contribute significantly to
achieving increases to production totals. Collecting the geological history from
the existing wells has indicated that the Company has three wells that need to
be relocated to a more productive part of the structure. The Company also has
two existing wells which fluid control methods can only be addressed by
re-drilling both locations. The Company will "twin" one of these wells, turning
the non-productive gas well into a shallow oil well, and re-drill the deeper gas
zone with efforts at controlling production of fluids from the start. The
Company will plug the other existing well because of mechanically damaged pipe
and then "relocate" this well to a more promising location. Re-drilling of the
two existing wells is expected to begin in April. The Company believes that
these five new wells can be strategically located due to the high degree of
information it has developed from its existing wells as to the shape and key
producing horizons of the Knox Formation. The Company is hopeful that production
from these new wells will be in line with the production from its best existing
wells in the Swan Creek Field and will have a noticeable effect on increasing
the total production from the Field.
10
The Company expects the repair work to existing wells and the
drilling of the five new wells in the Knox formation to be completed in the next
six months. Although no assurances can be made, the Company believes that, once
this work is completed and the new wells are drilled, production from the Swan
Creek Field will substantially increase by the end of 2002.
The Company also intends to commence drilling in other formations in
its Swan Creek Field. To date, drilling in the Swan Creek Field has focused on
production of gas primarily from the Knox formation. This is a lower Ordovician
Dolomite, and the heart of the anticline structure at Swan Creek. However,
immediately adjacent to this formation and shallower over these formations are
other formations which the Company believes have a potential for gas production.
The Stones River and Trenton formations hold the possibility for both oil and
gas and have produced some gas to date. These Upper Ordovician formations have
not been a primary target for gas production, but the shallower depths needed
for drilling and the moderate gas production might make a potential subsequent
source for additional gas production. With the completion of only one well in
the Trenton formation which is producing approximately 100Mcf per day, the
impact of these targets is proportional both to an area and an extent that is
yet undefined. The Company also plans to drill a 12,000 to 15,000 feet deep test
well in the Company's Swan Creek field, which the Company believes may have high
potential for significant additional volumes of natural gas. The current wells
in this field are all approximately 5,000 feet deep. Drilling is expected to
commence on or before December 31, 2002. The target of this drilling will be the
Conasauga and Rome formations from the lower and middle Cambrian ages.
As of the present time the Company does not anticipate that it will
be able to fulfill the maximum delivery requirements under its contracts with
Eastman and BAE from its existing wells. However, based on the reserve analysis
report of the Swan Creek Field, the Company believes that once it continues its
program of drilling new wells in the Swan Creek Field it will eventually produce
sufficient gas to meet these requirements. No assurances, however, can be given
that it will meet these goals.
Oil production in the Swan Creek Field declined from 47,281 barrels
in 2000 to 30,323 barrels in 2001. This decline was due primarily from the
natural decline process in existing wells and as a result of work on existing
wells to deal with the fluid problems discussed above. The Company is presently
reviewing key areas for drilling of new oil wells in the Swan Creek Field and it
is anticipated that in the fourth quarter of 2002 drilling of new wells to
increase oil production will begin. In addition, chemical treatments to enhance
production from existing wells are presently being studied and may be undertaken
if the Company believes the results of such treatments will be cost effective.
11
2. THE KANSAS PROPERTIES
The Company, as of December 31, 1997 acquired the Kansas Properties
which presently includes 134 producing oil wells and 51 producing gas wells in
the vicinity of Hays, Kansas and a gathering system including 50 miles of
pipeline. The Company also acquired 37 other wells which now serve as saltwater
disposal wells in the vicinity of Hays, Kansas. Saltwater wells are used to
store saltwater encountered in the drilling process that would otherwise have to
be transported out of the area. These saltwater disposal wells reduce operating
costs by eliminating the need for transport. The aggregate production for the
Kansas Properties at present is approximately one MMcf and 400 barrels of oil
per day. Revenue for the Kansas Properties is approximately $315,000 per month.
The Company has hired a full time geologist in Kansas to oversee
operations in the Kansas Properties. Recent well workovers in Kansas have
improved production with an estimated $1.80 increase in revenue for every $1.00
in work expense. The Company plans to drill five new wells in Ellis and Rush
Counties, Kansas on its existing leases in response to drilling activity in the
area establishing new areas of production. In 2001 the Company successfully
drilled the Dick No. 7 well in Kansas and completed the well as an oil well. The
Company is also engaged in gathering for a fee the gas produced from wells owned
by others located in Kansas adjacent to the Company's wells and near the
Company's gathering lines. The Company's plans for its Kansas properties include
maintaining the current productive capacity of its existing wells through normal
workovers and maintenance of the wells, performing gathering or sales services
for adjacent producers, and expanding the Company's own production through
drilling these additional wells. Such plans are subject to the availability of
funds to perform the work.
In addition, there are several capital development projects that are
available with respect to the Kansas Properties which include recompletion of
wells and major workovers to increase current production. These projects when
completed may increase production in Kansas. Management, however, has made the
decision not to perform this work at the present time, as the Company does not
presently have the funds necessary to perform these projects. It will however,
reconsider its decision if such funds become available through the Company's
operations or other sources of financing.
3. OTHER AREAS OF DEVELOPMENT
On August 10, 2001, the Company and Penn Virginia Oil & Gas
Corporation, a subsidiary of Penn Virginia Corporation entered into a joint
operating agreement to explore, drill and develop a certain area of mutual
interest in East Tennessee and southern Virginia. Both companies will share
equally all lease acquisition costs, seismic exploration and analysis costs,
drilling and operating costs, as well as the proceeds from production. Penn
Virginia is named as the initial operator under the joint operating agreement.
Penn Virginia has begun the seismic program and drilling operations will be
based on the results of seismic analysis. No assurances
12
can be made at this time of the amount of reserves that may be discovered or
produced in the course of this venture.
The Company is presently exploring other geological structures in
the East Tennessee area that are similar to the Swan Creek structure and which
the Company believes have a high probability of producing hydrocarbons. The
Company has either acquired seismic data on these structures from third-party
sources, or is conducting its own seismic studies with its own trucks and
equipment. The seismic data is being analyzed at the University of Tennessee as
part of the strategic alliance between the Company and the University of
Tennessee. The seismic analysis is continuing and related leasing activities
have begun based on initial analysis of seismic results. The Company plans to
conduct exploration activities in these areas. The first of these locations will
be in Cocke County, Tennessee which is approximately 40 miles southeast of the
Swan Creek Field. The Company, in conjunction with Southeast Gas & Oil Corp. of
Newport, Tennessee, plans to drill an approximately 6,000-foot exploratory well
to the Knox formation. If the well is successful this will lead to additional
wells being drilled for new field evaluation. The Company also expects to
explore one other new structure this year.
GOVERNMENTAL REGULATIONS
The Company is subject to numerous state and federal regulations,
environmental and otherwise, that may have a substantial negative effect on its
ability to operate at a profit. For a discussion of the risks involved as a
result of such regulations, see, "Effect of Existing or Probable Governmental
Regulations on Business" and "Costs and Effects of Compliance with Environmental
Laws" hereinafter in this section.
PRINCIPAL PRODUCTS OR SERVICES AND MARKETS
The Company will conduct exploration and production activities to
produce crude oil and natural gas. The principal markets for these commodities
are local refining companies, local utilities and private industry end users,
which purchase the crude oil, and local utilities, private industry end users,
and natural gas marketing companies, which purchase the natural gas.
Gas production from the Swan Creek field can presently be delivered
through the Company's completed pipeline to the Powell Valley Utility District
in Hancock County, Eastman and BAE in Sullivan County, as well as other
industrial customers in the Kingsport area. The Company has acquired all
necessary regulatory approvals and 100% of necessary property rights for the
pipeline system. The Company's pipeline will not only provide transportation
service for gas produced from the Company's wells, but will provide
transportation of gas for small independent producers in the local area as well.
Direct sales could also be made to some local towns, industries and utility
districts.
13
Natural gas from the Kansas Properties is delivered to
Kansas-Nebraska Energy, Inc. in Bushton, Kansas. At present, crude oil is sold
to the National Cooperative Refining Association in McPherson, Kansas, 120 miles
from Hays. National Cooperative is solely responsible for transportation of the
oil it purchases whether by truck or pipeline. There is a limited market in the
area and the only other purchaser of crude oil is EOTT Energy Operations Ltd.
DRILLING EQUIPMENT
In addition to the drilling equipment and vehicles which it acquired
from IRC, on November 1, 2000, the Company purchased an Ingersoll Rand RD20
drilling rig and related equipment from Ratliff Farms, Inc., an affiliate of
Malcolm E. Ratliff, Chief Executive Officer and Chairman of the Board of
Directors of the Company. See "Certain Relationships and Related Transactions" -
"Transactions with Management and Others." All of this equipment is in
satisfactory operating condition. The Company also receives contract drilling
services from Miller Petroleum, Inc. and Union Drilling in the Swan Creek Field.
DISTRIBUTION METHODS OF PRODUCTS OR SERVICES
Crude oil is normally delivered to refineries in Tennessee and
Kansas by tank truck and natural gas is distributed and transported via
pipeline.
COMPETITIVE BUSINESS CONDITIONS, COMPETITIVE POSITION IN THE INDUSTRY AND
METHODS OF COMPETITION
The Company's contemplated oil and gas exploration activities in the
States of Tennessee and Kansas will be undertaken in a highly competitive and
speculative business atmosphere. In seeking any other suitable oil and gas
properties for acquisition, the Company will be competing with a number of other
companies, including large oil and gas companies and other independent operators
with greater financial resources. Management does not believe that the Company's
initial competitive position in the oil and gas industry will be significant.
Its principal competitors in the State of Tennessee are Ashland Oil
and Miller Services. In the area of the Company's pipeline, the Company is in a
favorable position since it owns the only pipeline within a 20 mile radius.
Within that area, the Company owns leases on approximately 50,500 acres. There
are numerous producers in the area of the Kansas Properties. Some are larger and
some smaller than the Company. However, management expects that it will be able
to sell all of the gas and oil that the Kansas Properties produce.
Management does not foresee any difficulties in procuring drilling
rigs or the
14
manpower to run them in the area of its operations. The experience of management
has been that in most instances, drilling rigs have only a one or two day
waiting period; however, several factors, including increased competition in the
area, may limit the availability of drilling rigs, rig operators and related
personnel and/or equipment; such an event may have a significant adverse impact
on the profitability of the Company's operations.
The Company anticipates no difficulty in procuring well drilling
permits which are obtained from the Tennessee Oil and Gas Board. They are
usually issued within one week of application. The Company generally does not
apply for a permit until it is actually ready to commence drilling operations.
The prices of the Company's products are controlled by the world oil
market and the United States natural gas market; thus, competitive pricing
behaviors are considered unlikely; however, competition in the oil and gas
exploration industry exists in the form of competition to acquire the most
promising acreage blocks and obtaining the most favorable prices for
transporting the product. Management believes that the Company is
well-positioned in these areas because of the transmission lines that run
through and adjacent to the properties leased by the Company and because the
Company holds relatively large acreage blocks in what management believes are
promising areas.
SOURCES AND AVAILABILITY OF RAW MATERIALS
AND NAMES OF PRINCIPAL SUPPLIERS
Excluding the development of oil and gas reserves and the production
of oil and gas, the Company's operations are not dependent on the acquisition of
any raw materials. See, "Competitive Business Conditions, Competitive Position
in the Industry and Methods of Competition" set forth above.
DEPENDENCE ON ONE OR A FEW MAJOR CUSTOMERS
The Company is presently dependent upon a small number of customers
for the sale of gas from the Swan Creek Field, principally Eastman and BAE, and
other industrial customers in the Kingsport area with which the Company may
enter into gas sales contracts.
Natural gas from the Kansas Properties is delivered to
Kansas-Nebraska Energy, Inc. in Bushton, Kansas. At present, crude oil from the
Kansas Properties is being trucked and transported through pipelines to the
National Cooperative Refining Association in McPherson, Kansas, 120 miles from
Hays, Kansas. National Cooperative is solely responsible for transportation of
products whether by truck or pipeline. There is a limited market in the area and
the only other purchaser of crude oil is EOTT Energy Operations Ltd. The
Company, however, anticipates that it will be able to sell all of the oil and
gas produced from the Kansas Properties.
15
PATENTS, TRADEMARKS, LICENSES, FRANCHISES, CONCESSIONS,
ROYALTY AGREEMENTS OR LABOR CONTRACTS, INCLUDING DURATION
Royalty agreements relating to oil and gas production are standard
in the industry. The amount of the Company's royalty payments varies from lease
to lease. The amounts of the royalties on each of the Company's leases may be
obtained from the Company.
NEED FOR GOVERNMENTAL APPROVAL OF PRINCIPAL PRODUCTS OR SERVICES
None of the principal products offered by the Company require
governmental approval; however, permits are required for drilling oil or gas
wells. See, "Effect of Existing or Probable Governmental Regulations on
Business" below in this section.
The transportation service offered by Tengasco Pipeline is subject
to regulation by the Tennessee Regulatory Authority to the extent of certain
construction, safety, tariff rates and charges, and nondiscrimination
requirements under state law. These requirements are typical of those imposed on
regulated utilities. Tengasco Pipeline has been granted a certificate of public
convenience and necessity to operate as a pipeline utility in Hancock, Hawkins,
and Claiborne counties, Tennessee. In addition, Tengasco Pipeline was authorized
to construct and operate the portion of Phase II of the pipeline to Eastman by
resolution of the City of Kingsport in May, 2000. This resolution was approved
by the Tennessee Regulatory Authority as required by state law. All approvals
for the Company's pipeline have been granted.
The City of Kingsport, Tennessee has also enacted an ordinance dated
June 6, 2000 granting to Tengasco Pipeline a franchise for twenty years to
construct, maintain and operate a gas system to import, transport, and sell
natural gas to the City of Kingsport and its inhabitants, institutions and
businesses for domestic, commercial, industrial and institutional uses. This
ordinance and the franchise agreement it authorizes also require approval of the
Tennessee Regulatory Authority under state law. Now that the pipeline to Eastman
has been completed, Tengasco Pipeline and the City of Kingsport will initiate
the required approval process for the ordinance and franchise agreement. The
Company is in discussions with the City of Kingsport in preparation for filing
for regulatory approval and anticipates that the filing will be made in the next
sixty days. Although the Company anticipates that regulatory approval will be
granted, there can be no assurances that it will be granted, or that such
approval may be granted in a timely manner, or that such approval may not be
limited in some manner by the Tennessee Regulatory Authority as is expressly
permitted under state law.
Tengasco Pipeline presently has all required tariffs and approvals
necessary to transport natural gas to all customers of the Company. See, "Effect
of Existing or Probable Governmental Regulations on Business" below in this
section.
16
EFFECT OF EXISTING OR PROBABLE GOVERNMENTAL REGULATIONS ON BUSINESS
Exploration and production activities relating to oil and gas leases
are subject to numerous environmental laws, rules and regulations. The Federal
Clean Water Act requires the Company to construct a fresh water containment
barrier between the surface of each drilling site and the underlying water
table. This involves the insertion of a seven-inch diameter steel casing into
each well, with cement on the outside of the casing. The Company has fully
complied with this environmental regulation, the cost of which is approximately
$10,000 per well.
The State of Tennessee also requires the posting of a bond to ensure
that the Company's wells are properly plugged when abandoned. A separate $2,000
bond is required for each well drilled. The Company currently has the requisite
amount of bonds on deposit with the State of Tennessee.
As part of the Company's purchase of the Kansas Properties it
acquired a statewide permit to drill in Kansas. Applications under such permit
are applied for and issued within one-two weeks prior to drilling. At the
present time, the State of Kansas does not require the posting of a bond either
for permitting or to insure that the Company's wells are properly plugged when
abandoned. All of the wells in the Kansas Properties have all permits required
and are in compliance with the laws of the State of Kansas.
The Company's operations are also subject to laws and regulations
requiring removal and cleanup of environmental damages under certain
circumstances. Laws and regulations protecting the environment have generally
become more stringent in recent years, and may in certain circumstances impose
"strict liability," rendering a corporation liable for environmental damages
without regard to negligence or fault on the part of such corporation. Such laws
and regulations may expose the Company to liability for the conduct of
operations or conditions caused by others, or for acts of the Company which were
in compliance with all applicable laws at the time such acts were performed. The
modification of existing laws or regulations or the adoption of new laws or
regulations relating to environmental matters could have a material adverse
effect on the Company's operations. In addition, the Company's existing and
proposed operations could result in liability for fires, blowouts, oil spills,
discharge of hazardous materials into surface and subsurface aquifers and other
environmental damage, any one of which could result in personal injury, loss of
life, property damage or destruction or suspension of operations.
The Company believes it is presently in compliance with all
applicable federal, state or local environmental laws, rules or regulations;
however, continued compliance (or failure to comply) and future legislation may
have an adverse impact on the Company's present and contemplated business
operations.
The Company's Board of Directors adopted resolutions to form an
Environmental Response Policy and Emergency Action Response Policy Program. A
plan was adopted which provides for the erection of signs at each well and at
strategic locations along the pipeline
17
containing telephone numbers of the Company's office and the home telephone
numbers of key personnel. A list is maintained at the Company's office and at
the home of key personnel listing phone numbers for fire, police, emergency
services and Company employees who will be needed to deal with emergencies.
The foregoing is only a brief summary of some of the existing
environmental laws, rules and regulations to which the Company's business
operations are subject, and there are many others, the effects of which could
have an adverse impact on the Company. Future legislation in this area will no
doubt be enacted and revisions will be made in current laws. No assurance can be
given as to what effect these present and future laws, rules and regulations
will have on the Company's current and future operations. See, "Risk Factors",
below.
RESEARCH AND DEVELOPMENT
The Company has not expended any material amount in research and
development activities during the last two fiscal years. Research done in
conjunction with its exploration activities will consist primarily of conducting
seismic surveys on the lease blocks. This work will be performed by the
Company's geology and engineering personnel and other employees and will not
have a material cost of anything more than standard salaries.
COST AND EFFECTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS
See, "Effect of Existing or Probable Governmental Regulations on
Business" set forth above in this section.
NUMBER OF TOTAL EMPLOYEES AND NUMBER OF FULL-TIME EMPLOYEES
The Company presently has thirty-nine full time employees and no
part-time employees.
RISK FACTORS
In addition to the other information in this document, investors in
the Company's common stock should consider carefully the following risks:
VOLATILE OIL AND GAS PRICES CAN MATERIALLY AFFECT THE COMPANY. The
Company's future financial condition and results of operations will depend upon
the prices received for the Company's oil and natural gas production and the
costs of acquiring, finding, developing and producing reserves. Prices for oil
and natural gas are subject to fluctuations in
18
response to relatively minor changes in supply, market uncertainty and a variety
of additional factors that are beyond the control of the Company. These factors
include worldwide political instability (especially in the Middle East and other
oil-producing regions), the foreign supply of oil and gas, the price of foreign
imports, the level of drilling activity, the level of consumer product demand,
government regulations and taxes, the price and availability of alternative
fuels and the overall economic environment. A substantial or extended decline in
oil and gas prices would have a material adverse effect on the Company's
financial position, results of operations, quantities of oil and gas that may be
economically produced, and access to capital. Oil and natural gas prices have
historically been and are likely to continue to be volatile. This volatility
makes it difficult to estimate with precision the value of producing properties
in acquisitions and to budget and project the return on exploration and
development projects involving the Company's oil and gas properties. In
addition, unusually volatile prices often disrupt the market for oil and gas
properties, as buyers and sellers have more difficulty agreeing on the purchase
price of properties.
UNCERTAINTY IN CALCULATING RESERVES; RATES OF PRODUCTION;
DEVELOPMENT EXPENDITURES; CASH FLOWS . There are numerous uncertainties inherent
in estimating quantities of oil and natural gas reserves of any category and in
projecting future rates of production and timing of development expenditures,
which underlie the reserve estimates, including many factors beyond the
Company's control. Reserve data represent only estimates. In addition, the
estimates of future 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 the assumptions could result in the actual quantity of the
Company's reserves and future net cash flows from them being materially
different from the estimates. In addition, the Company's estimated reserves may
be subject to downward or upward revision based upon production history, results
of future exploration and development, prevailing oil and gas prices, operating
and development costs and other factors.
OIL AND GAS OPERATIONS INVOLVE SUBSTANTIAL COSTS AND ARE SUBJECT TO
VARIOUS ECONOMIC RISKS. The oil and gas operations of the Company are subject to
the economic risks typically associated with exploration, development and
production activities, including the necessity of significant expenditures to
locate and acquire producing properties and to drill exploratory wells. In
conducting exploration and development activities, the presence of unanticipated
pressure or irregularities in formations, miscalculations or accidents may cause
the Company's exploration, development and production activities to be
unsuccessful. This could result in a total loss of the Company's investment. In
addition, the cost and timing of drilling, completing and operating wells is
often uncertain.
SIGNIFICANT CAPITAL REQUIREMENTS. The Company must make a
substantial amount of capital expenditures for the acquisition, exploration and
development of oil and gas reserves. Historically, the Company has paid for
these expenditures with cash from operating activities, proceeds from debt and
equity financings and asset sales. The Company's ability to re-work existing
wells and complete its drilling program in the Swan Creek Field is dependent
upon its ability to fund these costs. Although the Company anticipated that by
this time it would be able
19
to fund the completion of its drilling program in the Swan Creek Field from
revenues from the sales of gas, it is unable to do so. Further, the Company's
credit facility with Bank One Corp. has been reduced by Bank One, although the
Company vigorously disputes the Bank's actions. 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, it must obtain the necessary funds to complete its
drilling program from other sources such as equity investment, bank loan or a
joint venture with another company. Although the Company believes that it will
be able to procure such financing, there can be no assurances that it will be
able to obtain such funding. In addition, the Company's revenues or cash flows
could be reduced because of lower oil and gas prices or for some other reason.
If the Company's revenues or cash flows decrease and the Company is unable to
procure alternative financing, this would require the Company to reduce
production over time. Where the Company is not the majority owner or operator of
an oil and gas project, it may have no control over the timing or amount of
capital expenditures associated with the particular project. If the Company
cannot fund its capital expenditures, its interests in some projects may be
reduced or forfeited.
COSTS INCURRED TO CONFORM TO GOVERNMENT REGULATION OF THE OIL AND
GAS INDUSTRY. The Company's exploration, production and marketing operations are
regulated extensively at the federal, state and local levels. The Company has
made and will continue to make large expenditures in its efforts to comply with
the requirements of environmental and other regulations. Further, the oil and
gas regulatory environment could change in ways that might substantially
increase these costs. Hydrocarbon-producing states regulate conservation
practices and the protection of correlative rights. These regulations affect the
Company's operations and limit the quantity of hydrocarbons the Company may
produce and sell. In addition, at the U.S. federal level, the Federal Energy
Regulatory Commission regulates interstate transportation of natural gas under
the Natural Gas Act. Other regulated matters include marketing, pricing,
transportation and valuation of royalty payments.
COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS. The Company, as an
owner or lessee and operator of oil and gas properties, is subject to various
federal, state and local laws and regulations relating to discharge of materials
into, and protection of, the environment. These laws and regulations may, among
other things, impose liability on the lessee under an oil and gas lease for the
cost of pollution clean-up resulting from operations, subject the lessee to
liability for pollution damages, and require suspension or cessation of
operations in affected areas.
The Company maintains insurance coverage, which it believes is
customary in the industry, although it is not fully insured against all
environmental risks. The Company is not aware of any environmental claims
existing as of December 31, 2001, which would have a material impact upon the
Company's financial position or results of operations.
The Company has made and will continue to make expenditures in its
efforts to comply with these requirements, which it believes are necessary
business costs in the oil and gas industry. The Company has established policies
for continuing compliance with environmental laws and regulations. The costs
incurred by these policies and procedures are inextricably
20
connected to normal operating expenses such that the Company is unable to
separate the expenses related to environmental matters; however, the Company
does not believe any such additional expenses are material to its financial
position or results of operations.
The Company does not believe that compliance with federal, state or
local provisions regulating the discharge of materials into the environment, or
otherwise relating to the protection of the environment, will have a material
adverse effect upon the capital expenditures, earnings or competitive position
of the Company or its subsidiaries; however, there is no assurance that changes
in or additions to laws or regulations regarding the protection of the
environment will not have such an impact.
INSURANCE DOES NOT COVER ALL RISKS. Exploration for and production
of oil and natural gas can be hazardous, involving unforeseen occurrences such
as blowouts, cratering, fires and loss of well control, which can result in
damage to or destruction of wells or production facilities, injury to persons,
loss of life, or damage to property or the environment. The Company maintains
insurance against certain losses or liabilities arising from its operations in
accordance with customary industry practices and in amounts that management
believes to be prudent; however, insurance is not available to the Company
against all operational risks.
HEDGING MAY PREVENT THE COMPANY FROM FULLY BENEFITTING FROM PRICE
INCREASES. The Company has entered into hedging activities for the period from
January 1, 2002 through July 31, 2002, that protect against price deterioration.
To the extent that it does so, it may be prevented from realizing the benefits
of price increases above the levels of the hedges. In addition, the Company is
subject to basis risk when it engages in hedging transactions, particularly
where transportation constraints restrict the Company's ability to deliver oil
and gas volumes at the delivery point to which the hedging transaction is
indexed.
GENERAL ECONOMIC CONDITIONS. Virtually all of the Company's
operations are subject to the risks and uncertainties of adverse changes in
general economic conditions, the outcome of pending and/or potential legal or
regulatory proceedings, changes in environmental, tax, labor and other laws and
regulations to which the Company is subject, and the condition of the capital
markets utilized by the Company to finance its operations.
ITEM 2. DESCRIPTION OF PROPERTY
PROPERTY LOCATION, FACILITIES, SIZE AND NATURE OF OWNERSHIP
The Company's Swan Creek Leases are on approximately 50,500 acres in
Hancock, Claiborne, Knox, Jefferson and Union Counties in Tennessee. The initial
terms of these leases vary from one to five years. Many of them can be extended
at the option of the Company by payment of annual rent. Some of them will
terminate unless the Company has commenced
21
drilling. However, the Company does not anticipate any difficulty in continuing
the Swan Creek Leases.
Morita Properties, Inc., an affiliate of Shigemi Morita, a former
Director of the Company, currently has a 25% working interest in nine of the
Company's existing wells, and a 50% working interest and 6% working interest in
two of the Company's other existing wells. All of these wells are located in the
Swan Creek Field and are presently producing wells. In addition, to those
interests, Morita Properties, Inc. previously owned a 25% working interest in
three of the Company's other existing wells and 12.5% working interest in
another of the Company's wells which it subsequently sold.
An individual who is not an affiliate of the Company purchased 25%
working interests in two other wells, the Stephon Lawson No. 1 and the Patton
No. 1. Both of these wells are located in the Swan Creek Field and are presently
producing wells.
Another individual has a 29% revenue interest in the Laura Jean
Lawson No. 3 well by virtue of having contributed her unleased acreage to the
drilling unit and paying her proportionate share of the drilling costs of the
well. The Company was obligated to allow that individual to participate on that
basis in accordance with both customary industry practice and the requirements
of the procedures of the Tennessee Oil and Gas Board in a forced pooling action
brought by the Company to require the acreage to be included in the unit so that
the well could be drilled. The forced pooling procedure was concluded by her
contribution of acreage and agreement to pay proportionate share of drilling
costs. This well is also located in the Swan Creek Field and is a presently
producing well.
The Company also entered into a farmout agreement with Miller
Petroleum, Inc. ("Miller") for ten wells to be drilled in the Swan Creek Field
with the Company having an option to award up to an additional ten future wells.
All locations were to be mutually agreed upon. Net revenues are to be 81.25% to
Miller and the Company's subsidiary Tengasco Pipeline will transport Miller's
gas. The Company reserved all offset locations to wells drilled under the
farmout agreement. All ten wells have been drilled under the farmout agreement.
The Company acquired back from Miller a 50% working interest from Miller in nine
of those ten wells in addition to its rights under the farmout agreement. In
addition, the Company and Miller have drilled two additional wells on a 50-50
basis, although the Company declined to exercise its option for a ten-well
extension of the farmout agreement. Of the wells in which Miller owns an
interest, six are presently producing.
Other than the working interests described or referred to in this
Item, the Company retains all other working interests in wells drilled or to be
drilled in the Swan Creek Field.
Working interest owners in oil and gas wells are entitled to market
their respective shares of production to purchasers other than purchasers with
whom the Company has contracted. Absent such contractual arrangements being made
by the working interest owners, the Company is authorized but is not required to
provide a market for oil or gas attributable to working interest
22
owners' production. At this time, the Company has not agreed to market gas for
any working interest owner to customers other than customers of the Company. If
the Company does agree to market gas for working interest owners to the
Company's customers, the Company will have to agree, at that time, to the terms
of such marketing arrangements and it is possible that as a result of such
arrangements, the Company's revenues from such customers may be correspondingly
reduced. If the working interest owners make their own arrangements to market
their natural gas to other end users along the pipeline which have been served
by East Tennessee Natural Gas, an interstate pipeline, such gas would be
transported through the Company's wholly owned subsidiary Tengasco Pipeline at
published tariff rates. The current published tariff rate is for firm
transportation at a demand charge of five cents per MMBtu per day plus a
commodity charge of $0.80 per MMBtu. If the working interest owners do not
market their production, either independently or through the Company, then their
interest will be treated as not yet produced and will be balanced either when
marketing arrangements are made by such working interest owners or when the well
ceases to produce in accordance with customary industry practice.
The Kansas Properties contain 138 leases totaling 32,158 acres in
the vicinity of Hays, Kansas. The original term on these leases was from 1 to 10
years and in most cases has expired, however, most leases are still in effect
because they are being held by production. The Company maintains a 100% working
interest in most wells. The leases provide for a landowner royalty of 12.5%.
Some wells are subject to an overriding royalty interest from 0.5% to 9%.
The Company pays ad valorem taxes on its Kansas Properties. It does
not pay any taxes on its Swan Creek Leases. The Company has general liability
insurance for the Kansas Properties and the Swan Creek Field.
The Company leases its principal executive offices, consisting of
approximately 5,647 square feet located at 603 Main Avenue, Suite 500,
Knoxville, Tennessee, at a monthly rent of $4,705.83. The Company also leases a
field office in Sneedville, Tennessee at a rental of $500 per month, an office
in Hays, Kansas at a rental of $500 per month and an office in New York City at
a rental of $2,600 per month.
RESERVE ANALYSES
Ryder Scott Company, L.P. of Houston, Texas ("Ryder Scott") has
performed reserve analyses of all the Company's productive leases. Ryder Scott
and its employees and its registered petroleum engineers have no interest in the
Company or IRC, and performed these services at their standard rates. The net
reserve values used hereafter were obtained from a reserve report dated March
28, 2002 (the "Report") prepared by Ryder Scott as of December 31, 2001. In
substance, the Report used estimates of oil and gas reserves based upon standard
petroleum engineering methods which include production data, decline curve
analysis, volumetric calculations, pressure history, analogy, various
correlations and technical judgment. Information for this purpose was obtained
from owners of interests in the areas involved, state regulatory agencies,
commercial services, outside operators and files of Ryder Scott. The net reserve
values
23
in the Report were adjusted to take into account the working interests that have
been sold by the Company in various wells in the Swan Creek Field. The Report
provides that the net proved reserves for wells in the Swan Creek Field is
23,006 MMcf of natural gas and 224,745 barrels of oil. According to the Report,
the value of the future gross revenues of the Company's interest in the Swan
Creek Field as of December 31, 2001 is $57,832,005 before production taxes and
$56,097,044 after production taxes. The Report further provides that as of
December 31, 2001 the value of the future net income before income taxes of the
Company's interest in the Swan Creek Field is $41,478,067 and discounting the
future net income by 10% results in a present value of $19,302,590.
The Report reflects a reduction in the amount of proved natural gas
reserves from 33,576.581 MMcf to 23,006.332 MMcf and proved oil reserves from
284,673 barrels to 224,745 barrels in the Swan Creek Field from the reserves as
provided in the Ryder Scott report dated August 10, 2001 reporting values as of
June 30, 2001. This reduction is a result of the later Report placing greater
emphasis on the initial production figures from the Swan Creek Field during the
period from June to December 2001 which were adversely affected by initial
production problems as described above in "Item 1 Business - General - 1. Swan
Creek". The earlier Ryder Scott report as of June 30, 2001, on the other hand,
was based primarily on volumetric calculations rather than actual production
figures because production from the Swan Creek had just begun. The Company
anticipates that the reserve report will not only stabilize at no less than
current levels of production but increase in future reporting periods when it is
expected that production will increase as a result of ongoing work on existing
wells and the drilling of new wells. The Report also reflects a reduction of
48.8% in the net present value of the oil and gas reserves in the Swan Creek
Field from the values reported in the Ryder Scott reserve report dated June 30,
2001. This reduction occurred not only as a result of the amount of reserves
reported, but in addition, as a result of the much lower oil and gas prices
being received at year end as stated in the Report which were approximately
$7.75 per barrel of oil and $.80 Mcf of gas lower than the prices which served
as the basis for Ryder Scott's earlier June 30, 2001 report.
The Report reflects a substantial reduction in the amount of proved
natural gas reserves from 44,451.338 MMcf to 23,006.332 MMcf and proved oil
reserves from 376,296 barrels to 224,745 barrels in the Swan Creek Field from
the reserves in an earlier Ryder Scott reported dated March 28, 2001 reporting
values as of December 31, 2000.This results from the fact that the earlier
report was based entirely on volumetric calculations because production had not
yet commenced. In addition, the Report reflects a significant reduction of the
discounted (at 10% per annum compounded monthly) net present value of the
Company's oil and gas reserves in the Swan Creek field from $300,208,036 to
$19,302,590. Although this reduction is based in part on the reduction in
reserves for the reasons stated, a most significant factor in this reported
reduction of net present value is the use of much lower price projections in the
valuation of the reserves. The year-end 2000 report utilized near-record gas
prices of $9.77 per Mcf and oil prices of $24.10 per barrel as opposed to the
$2.13 per Mcf price and $17.24 per barrel price utilized in the current Report
for the year ending December 31, 2001. This represents a 78% reduction in gas
prices, and a 28% reduction in oil prices. Finally, the reduction in net present
value as stated in the Report also occurred in part because the projected life
of the Swan Creek
24
reserves for the year ending December 31, 2001 is more than doubled (from 26.14
years to 57.67 years) from the report for the year ending December 31, 2000.
This has the arithmetical result of amplifying the effect of the ten percent
(compounded monthly) discount factor used in determining a net present value of
the total future income stream, because the discount factor is applied and
compounding occurs over the longer period of time (56.7 years as opposed to
26.14 years) during which production is projected to occur.
Ryder Scott also performed a reserve analysis of the Kansas
Properties. The Report provides that the net proved reserves for wells in the
Swan Creek Field is 2,873 MMcf of natural gas and 831,930 barrels of oil.
According to the Report, the value of the future gross revenues of the Company's
interest in the Kansas Properties as of December 31, 2001 is $20,463,797 before
production taxes and $19,586,607 after production taxes. The Report further
provides that as of December 31, 2001 the value of the future net income before
income taxes of the Company's interest in the Kansas Properties is $4,350,410
and discounting the future net income by 10% results in a present value of
$2,431,317.
The Report reflects a reduction from the earlier Ryder Scott report
as of December 31, 2000 in (i) the number of barrels of oil attributed to the
Company's net interest in the Kansas Properties from 1,438,209 barrels to
831,930 barrels and (ii) the value of the future gross revenues of the Company's
interest in the Kansas Properties from $54,419,609 before production taxes and
$54,307,992 after production taxes as of December 31, 2000 to $20,463,797 before
production taxes and $19,586,607 after production taxes as of December 31, 2001.
These reductions are due primarily to two factors. First, the reduction in the
number of barrels occurred because the Report disregarded the reserves
attributable to approximately thirty wells that are still actually producing
oil, because the calculated operating expenses for those wells matched or
exceeded the theoretical crude oil price being utilized in the Report. Because
the current market price of crude oil has risen from the price used in the
Report, all or a portion of the reserves attributable to these wells would now
be included in an analysis of the Company's reserves, depending upon the level
of price received for crude oil and the relationship of such price to operating
expenses. Second, the Report in determining the value of future gross revenues
from the Kansas Properties used lower prices than utilized in the report ending
December 31, 2000. The Report used a gas price of $2.13 in contrast to the $5.30
price used in 2000, and an oil price of $17.21 in contrast to the $26.46 price
used in 2000. The combination of these factors also resulted in a decrease in
the net present value of the Company's future income from the Kansas Properties
calculated at a discount of 10%, from $14,993,222 as of December 31, 2000 to
$2,431,317 as of December 31, 2001. The Company anticipates that future reports
of the net present value of the Kansas Properties will rise with any increase in
market pricing and the resulting consideration of reserves attributable to all
of the Company's wells, which are still producing in accordance with their
extended production history.
The Company believes that the reserve analysis reports prepared by
Ryder Scott for the Company for the Swan Creek Field and Kansas Properties
provide an essential basis for review and consideration of the Company's
producing properties by all potential industry partners and all financial
institutions across the country. It is standard in the industry for reserve
analyses such as these to be used as a basis for financing of drilling costs.
Reserve analyses, however, are
25
at best speculative, especially when based upon limited production; no assurance
can be given that the reserves attributed to these leases exist or will be
economically recoverable. The result of any reserve analysis is dependent upon
the forecast of product prices utilized in the analysis which may be more or
less than the actual price received during the period in which production
occurs.
The Company has not filed the reserve analysis reports prepared by
Ryder Scott or any other reserve reports with any Federal authority or agency
other than the Securities and Exchange Commission.
PRODUCTION
The following tables summarize for the past three fiscal years the
volumes of oil and gas produced to the Company's interests, the Company's
operating costs and the Company's average sales prices for its oil and gas. The
information does not include volumes produced to royalty interests or other
working interests.
- --------------------------------------------------------------------------------
TENNESSEE
- --------------------------------------------------------------------------------
YEAR ENDED PRODUCTION COST OF PRODUCTION AVERAGE SALES PRICE
DECEMBER 31 (PER BOE)(2)
- --------------------------------------------------------------------------------
OIL GAS OIL GAS
(Bbl) (Mcf) (Bbl) (PER Mcf)
- --------------------------------------------------------------------------------
2001 22,776.21 703,073.56 $0.31 $16.05 $2.55
- --------------------------------------------------------------------------------
2000 37,210.67 2,411.00 $0.69 $20.32 $2.86
- --------------------------------------------------------------------------------
1999 17,286.06 2,122.00 $0.44(est.) $12.81 $2.86(est.)
- --------------------------------------------------------------------------------
Gas volumes and prices for 1999 and 2000 reflect only the nominal purchases made
by Hawkins County Gas Utility District upon completion of Phase I of Tengasco
Pipeline Company's pipeline system. See Item I, "Business-General-1 Swan Creek
Field."
- ----------
(2) A "BOE" is a barrel of oil equivalent. A barrel of oil contains
approximately 6 Mcf of natural gas by heating content. The volumes of gas
produced have been converted into "barrels of oil equivalent" for the purposes
of calculating costs of production.
26
- --------------------------------------------------------------------------------
KANSAS
- --------------------------------------------------------------------------------
YEAR ENDED PRODUCTION COST OF PRODUCTION AVERAGE SALES PRICE
DECEMBER 31 (PER BOE)
- --------------------------------------------------------------------------------
OIL GAS OIL GAS
(Bbl) (Mcf) (Bbl) (PER Mcf)
- --------------------------------------------------------------------------------
2001 112,495.88 278,884.66 $10.72 $23.50 $4.12
- --------------------------------------------------------------------------------
2000 111,734.81 291,096.22 $ 9.68 $28.06 $3.75
- --------------------------------------------------------------------------------
1999 114,732.28 304,059.81 $ 8.87 $17.23 $2.16
- --------------------------------------------------------------------------------
OIL AND GAS DRILLING ACTIVITIES
The Company's oil and gas developmental drilling for the past three
fiscal years are as set forth in the following tables. During the fiscal years
ending December 31, 1999, 2000 and 2001, the Company did not drill any
exploratory wells. The information should not be considered indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the number of wells drilled, quantities of reserves found or economic
value.
GROSS AND NET WELLS
The following tables set forth for the fiscal years ending December
31, 1999, 2000 and 2001 the number of gross and net development wells drilled by
the Company. The term gross wells means the total number of wells in which the
Company owns an interest, while the term net wells means the sum of the
fractional working interests the Company owns in gross wells.
- --------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31
- --------------------------------------------------------------------------------
2001 2000 1999
- --------------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
- --------------------------------------------------------------------------------
TENNESSEE
- --------------------------------------------------------------------------------
PRODUCTIVE WELLS 19 11.42 9 4.0515 7 4.8125
- --------------------------------------------------------------------------------
DRY HOLES 0 0 0 0 0 0
- --------------------------------------------------------------------------------
KANSAS
- --------------------------------------------------------------------------------
PRODUCTIVE WELLS 3 2.594 0 0 0 0
- --------------------------------------------------------------------------------
DRY HOLES 0 0 0 0 0 0
- --------------------------------------------------------------------------------
27
PRODUCTIVE WELLS
The following table sets information regarding the number of
productive wells in which the Company held a working interest as of December 31,
2001. Productive wells are either producing wells or wells capable of commercial
production although currently shut-in. One or more completions in the same bore
hole are counted as one well.
- --------------------------------------------------------------------------------
GAS OIL
- --------------------------------------------------------------------------------
GROSS NET GROSS NET
- --------------------------------------------------------------------------------
TENNESSEE 34 20.7475 11 5.308
- --------------------------------------------------------------------------------
KANSAS 52 43.4504 134 112.8382
- --------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED OIL AND GAS ACREAGE
As of December 31, 2001, the Company owned working interests in the
following developed and undeveloped oil and gas acreage. Net acres refers to the
Company's interest less the interest of royalty and other working interest
owners.
- --------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED
- --------------------------------------------------------------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
- --------------------------------------------------------------------------------
TENNESSEE 1,840.00 1,065.38 62,651.90 54,820.00
- --------------------------------------------------------------------------------
KANSAS 9,666.00 8,080.44 22,711.00 18,995.48
- --------------------------------------------------------------------------------
ITEM 3. - 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
28
result materially adverse to the Company. To the knowledge of management, no
director, executive officer or affiliate of the Company or owner of record or
beneficially of more than 5% of the Company's common stock is a party adverse to
the Company or has a material interest adverse to the Company in any proceeding.
1. The Company, its Chief Executive Officer, Malcolm E. Ratliff,
and one of its attorneys, Morton S. Robson, have been named as defendants in an
action commenced in the Supreme Court of the State of New York, New York County
entitled MAUREEN COLEMAN, JOHN O. KOHLER, CHARLES MASSOUD, JONATHAN SARLIN, VON
GRAFFENRIED A.G. AND VPM VERWATUNGS A.G., PLAINTIFFS V. TENGASCO, INC., MORTON
S. ROBSON AND MALCOLM E. RATLIFF, DEFENDANTS, INDEX NO. 603009/98. In that
action, the plaintiffs, shareholders of the Company each of which purchased
restricted shares of the Company's Common Stock, allege that although they were
entitled to sell their shares pursuant to SEC Rule 144 in the open market, they
were precluded from doing so by the defendants' purported wrongful refusal to
remove the restrictive legend from their shares. The plaintiffs own in the
aggregate 35,000 shares of the Company's common stock. The plaintiffs are
seeking damages in an amount equal to the difference between the amount for
which they would have been able to sell their shares if the defendants had acted
to remove the restrictive legends when requested and the amount they will
receive on the sale of their shares. The plaintiffs are also seeking punitive
damages in an amount they claim to be in excess of $500,000 together with
interest, costs and disbursements of bringing the action, including reasonable
attorneys fees. This action has been partially settled by the Company agreeing
to remove the restrictive legends on the plaintiffs' stock.
As for the balance of the action, the Company believes that there
are several substantial factual and legal issues as to the date on which the
shareholders were entitled to sell their stock pursuant to Rule 144. Management
further believes that the Company did not wrongfully withhold its approval of
the removal of the restrictive legends at the times such removal was requested
by the shareholders. However, in the event the Company is found to have
improperly withheld its permission to remove the restrictive legends from the
shares owned by the shareholders, the Company may be held liable for damages to
the shareholders in an amount equal to the difference between the actual sale
price of such shares and the sales price they would have realized on the date
such restrictive legends should have been permitted to be removed. At this time
it is not possible to ascertain with any certainty what such damages would be.
The plaintiffs have not taken any action in this matter for several years.
2. TENGASCO PIPELINE CORPORATION V. JAMES E. LARKIN AND KATHLEEN
A. O `CONNOR, No. 4929J in the Circuit Court for Hawkins County, Tennessee. This
is a condemnation proceeding brought by Tengasco Pipeline Corporation to acquire
a temporary construction easement and permanent right of way to maintain and
operate a portion of Phase I of the Company's pipeline in Hawkins County,
Tennessee. The court granted an order of possession to the Company in January,
1998 and the pipeline has been constructed across approximately 3,000 feet of
the property concerned in a rural and very steep locale. The Company has had the
right of way appraised at $4,000. The landowners, Mr. Larkin and Kathleen A. O
Connor who both live on the property, contest the appraised value of the
property and claim incidental damages to
29
certain fish ponds located on their property. The landowners, despite a lack of
evidence of any fish raising or aquaculture business actually being or having
been operated on the premises or of any actual losses to such business, have
counterclaimed for $867,585 in compensatory damages and $2.6 million in punitive
damages arising from trespass and other legal theories. The Court required the
parties to attempt to mediate this dispute and the mediation occurred in
December, 2000. The parties were unable to reach a mediated settlement and the
matter has been scheduled for trial on May 8, 2002. The discovery conducted to
date has not disclosed any facts that reasonably suggest any likelihood of a
substantial adverse result in this matter, and the Company intends to vigorously
defend the allegations of the counterclaim which appear to be without any
credible basis.
3. The Company and its wholly owned subsidiary, Tengasco Pipeline
Corporation ("TPC"), were named as defendants in an action commenced on June 4,
2001 by C.H. Fenstermaker & Associates, Inc. ("Fenstermaker") in the United
States District for the Eastern District of Tennessee entitled C.H. FENSTERMAKER
& ASSOCIATES, INC. V. TENGASCO, INC., No. 3:01-CV-283.
The action seeks to recover approximately $365,000 in fees and
charges billed to TPC for engineering services Fenstermaker claims it performed
in connection with the planning and construction of Phase II of the Company's
pipeline which runs from Rogersville, TN to Kingsport, TN to serve Eastman
Chemical Company and Holston Army Ammunition Plant.
On June 25, 2001, the Company and TPC filed an answer to the
complaint denying liability for the billings claimed, and counterclaiming
against Caddum, Inc. ("Caddum"), an unincorporated division of Fenstermaker. The
counterclaim seeks recovery from Caddum of damages for breach of contract and
breach of professional engineering standards caused by the actions of Caddum,
including unauthorized deviations from the pipeline route which caused the
Company to incur significant additional costs. These costs included substantial
fees for concrete capping of the pipeline as a result of the pipeline being
placed to close to the adjoining highway right of way. The counterclaim further
alleges that Caddum damaged the Company by: causing delays in completing the
pipeline; by failing to submit engineering drawings and failing to timely obtain
certain x-rays of the pipeline welds; its unauthorized actions in ordering
supplies and materials; and, overbilling from the agreed contract rate for
engineering services. The counterclaim seeks actual damages from Caddum of
approximately $475,000, treble damages under state law for the overbilling, and
damages to the Company arising from the delay caused by Caddum in the production
from the Swan Creek field all in the aggregate amount of $1.25 million. The
District Court has scheduled the case for a non-jury trial on July 17, 2002
before Judge James H. Jarvis. The Company believes its counterclaims are
meritorious and intends to vigorously prosecute them and anticipates that, at a
minimum, its counterclaims will either fully offset or substantially reduce
exposure to liability for the amounts claimed by Fenstermaker.
4. On October 10, 2001 an arbitration hearing was held by the
American Arbitration Association between the Company's wholly owned subsidiary
Tengasco Pipeline Corporation ("TPC") and King Pipeline & Utility Company
("King"), the contractor for the
30
construction of Phase II of the Company's pipeline. The arbitration was held to
resolve disputes concerning final billings by King for the pipeline
construction. King made four claims, seeking (1) payment for straw matting done
by King on slopes calculated at two dollars per square foot; (2) to retain
payment it had received for clearing and grubbing charges; (3) the release of a
currently retained sum of $46,585, to which TPC made no claim, presently being
held in escrow pending the outcome of ongoing litigation between King and King's
boring subcontractor; and (4) payment of $94,000 billed by King for alleged
extra work it performed in trenching at a depth deeper than called for by the
contract.
On October 31, 2001 the arbitrator issued his award finding that
King was entitled to recover the sum of $266,390.66 for straw matting work
performed by King, calculated at $2 per square foot as sought by King; that King
was entitled to retain the $72,500 payment made to it by TPC for clearing and
grubbing work, and that the retained sum be released from escrow. The arbitrator
denied all relief sought by King for extra charges in the amount of $94,000 for
deeper trenching, and awarded King its attorneys fees of approximately $14,000.
TPC has filed a motion to vacate the arbitrator's award and King has filed an
opposing motion to confirm the award. The motions are expected to be heard
shortly in the Chancery Court for Knox County, Tennessee. In the event TPC's
motion is denied and King's opposing motion is granted, the Company is examining
the possibility of appealing the award, since the Company believes that the
arbitrator's ruling is not supported by the record presented. However, available
grounds for appeal appear extremely limited and it is therefore unlikely that an
appeal will occur. In the event an appeal is unavailable and payment is made to
satisfy the award, then based on the evidence presented at the arbitration
hearing, the Company and TPC intend to seek recovery of the payments made to
King as an additional element of damages being sought from Caddum, Inc., the
project engineer, in the action now pending in the United States District Court
for the Eastern District of Tennessee entitled C.H. FENSTERMAKER & ASSOCIATES,
INC. V. TENGASCO, INC., No. 3:01-CV-2 discussed above.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None during the fourth quarter of 2001.
31
PART II
ITEM 5 MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
The Company's common stock was listed on the OTC Bulletin Board of the NASD from
March 31, 1994 through December 20, 1999 under the symbol TNGO. On December 10,
1999, the American Stock Exchange ("AMEX") approved the application of the
Company to have its common stock listed on the AMEX. Trading of the Company's
common stock on the AMEX commenced on December 21, 1999 under the symbol TGC.
The range of high and low closing prices for shares of common stock
of the Company during the fiscal years ended December 31, 2000 and December 31,
2001 are set forth below. The prices have been retroactively adjusted by a 5%
reduction to take into account the 5% stock dividend declared by the Company
payable on October 1, 2001 to all shareholders of record as of September 4,
2001.
HIGH LOW
---- ---
For the Quarters Ending
March 31, 2001 14.20 9.69
June 30, 2001 15.01 11.16
September 30, 2001 13.69 7.60
December 31, 2001 10.54 7.39
March 31, 2000 9.86 6.65
June 30, 2000 9.26 6.65
September 30, 2000 9.26 7.60
December 31, 2000 12.82 7.84
32
HOLDERS
As of March 1, 2002 the number of shareholders of record of the
Company's common stock was 375 and management believes that there are
approximately 2,172 beneficial owners of the Company's common stock.
DIVIDENDS
The Company under its credit agreement with Bank One is presently
restricted from paying dividends without Bank One's consent. On July 30, 2001,
the Company's Board of Directors voted to declare a five percent (5%) stock
dividend on the outstanding shares of the Company's common stock, $.001 par
value which was payable on October 1, 2001 to all shareholders of record as of
September 4, 2001. No fractional shares were issued in connection with the stock
dividend and all such fractional shares were rounded to the next full share. The
Company has no present plans to declare any further dividends with respect to
its common stock.
RECENT SALES OF UNREGISTERED SECURITIES
Except as previously reported in Quarterly Reports on Form 10-QSB
and Form 10-Q filed by the Company, the following tables sets forth certain
information as to all equity securities, other than the grant of options, which
were sold during the past year, including the sale of common stock upon the
exercise of outstanding options and warrants, that were not registered under the
Securities Act of 1933, as amended,
COMMON STOCK
DATE NUMBER OF AGGREGATE
NAME OF OWNER ACQUIRED SHARES CONSIDERATION
- ------------- -------- ------ -------------
Kenny Securities 7/13/01 12,000 $ 82,500
Kenny Securities 7/13/01 17,285 $ 109,328
Bill L. Harbert 8/9/01 111,111 $1,000,000.00
Jerome & Lynn Cipponeri 12/31/01 16,000 $ 100,000.00
In addition to the foregoing, on December 20, 2001, the Company
issued 5,000 shares of its common stock to a non-affiliated individual in
payment of $70,000 for services he had performed for the Company.
33
Management believes that all of the foregoing persons were either
"accredited investors" as that term is defined under applicable federal and
state securities laws, rules and regulations, or were persons who by virtue of
background, education and experience who could accurately evaluate the risks and
merits attendant to an investment in the securities of the Company. Further, all
such persons were provided with access to all material information regarding the
Company, prior to the offer or sale of these securities, and each had an
opportunity to ask of and receive answers from directors, executive officers,
attorneys and accountants for the Company. The offers and sales of the foregoing
securities are believed to have been exempt from the registration requirements
of Section 5 of the 1933 Act, as amended, pursuant to Section 4(2) thereof, and
from similar state securities laws, rules and regulations covering the offer and
sale of securities by available state exemptions from such registration.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data have been derived from the
Company's financial statements, and should be read in conjunction with those
financial statements, including the related footnotes.
Years Ended December 31,
- ------------------------------ ----------- ----------- ----------- ----------- -----------
2001 2000 1999 1998 1997
- ------------------------------ ----------- ----------- ----------- ----------- -----------
INCOME STATEMENT DATA:
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Oil and Gas Revenues $ 6,656,758 $ 5,241,076 $ 3,017,252 $ 2,078,101 --
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Production Costs and Taxes $ 2,951,746 $ 2,614,414 $ 2,564,932 $ 1,943,944 $ 3,748
- ------------------------------ ----------- ----------- ----------- ----------- -----------
General and Administrative $ 2,957,871 $ 2,602,311 $ 1,961,348 $ 1,372,132 $ 1,535,841
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Interest Expense $ 850,965 $ 415,376 $ 417,497 $ 574,906 $ 1,885,448
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Net Loss $(2,262,787) $(1,541,884) $(2,671,923) $(3,083,638) $(4,370,570)
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Net Loss Available to Common $(2,653,970) $(1,799,441) $(2,791,270) $(3,083,638) $(4,370,570)
Stockholders
- ------------------------------ ----------- ----------- ----------- ----------- -----------
Net Loss Available to Common
Stockholders Per Share(3) $ (0.26) $ (0.19) $ (0.33) $ (0.42) $ (0.71)
- ------------------------------ ----------- ----------- ----------- ----------- -----------
- ----------
(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.
34
As of December 31,
- -------------------------------- ------------ ------------ ----------- ----------- -----------
2001 2000 1999 1998 1997
- -------------------------------- ------------ ------------ ----------- ----------- -----------
BALANCE SHEET DATA:
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Working Capital Deficit $ (6,326,204) $ (708,317) $(1,406,263) $(1,929,215) $(1,774,571)
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Oil and Gas Properties, Net $ 13,269,930 $ 9,790,047 $ 8,444,036 $ 7,747,655 $ 6,872,571
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Pipeline Facilities(4) $ 15,039,762 $ 11,047,038 $ 4,212,842 $ 4,019,209 $ 2,596,967
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Total Assets $ 32,128,245 $ 25,224,724 $15,182,712 $13,525,777 $14,644,811
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Long-Term Debt $ 3,902,757 $ 7,108,599 $ 3,119,293 $ 3,190,930 $ 2,006,293
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Redeemable Preferred Stock $ 5,459,050 $ 3,938,900 $ 1,988,900 $ 800,000 $ 0
- -------------------------------- ------------ ------------ ----------- ----------- -----------
Stockholder' Equity(5) $ 14,991,847 $ 10,864,202 $ 7,453,930 $ 7,245,090 $ 6,001,481
- -------------------------------- ------------ ------------ ----------- ----------- -----------
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
RESULTS OF OPERATIONS
The Company incurred a net loss to holders of common stock of
$2,653,970 ($0.26 per share) in 2001 compared to a net loss of $1,799,441 ($0.19
per share) in 2000 and $2,791,270 ($0.33 per share) in 1999.
The Company realized oil and gas revenues of $6,656,758 in 2001 as
compared to $5,241,076 in 2000 and $3,017,252 in 1999. The increase from 2000 to
2001 was primarily due to gas sales from the Swan Creek Field of $2,563,935.
However, Kansas oil sales decreased $489,778 from 2001 to 2000 due to price
decreases as the number of barrels produced remained constant. The Kansas
Properties produced 113,758 barrels in 1999, 143,949 barrels in 2000, and
143,291 barrels in 2001. Also oil production decreases and price decreases in
Swan Creek reduced oil revenues from $960,814 in 2000 to $499,641 in 2001. This
was due to the combination of price and volume. Volumes decreased from 47,281
barrels in 2000 to 30,323 barrels in 2001. This was due to the Company's
concentration on drilling new gas wells. The Company's subsidiary, Tengasco
Pipeline, did have pipeline transportation revenues for the first
- ----------
(4) During the years ended December 31, 2000, 1999, 1998 and 1997, this
included portions which were under construction.
(5) No cash dividends have been declared or paid by the Company for the
periods presented.
35
time in 2001 of $296,331 from the Swan Creek Field.
The Company's realized oil and gas revenues increased $2,223,824 in
2000 as compared to 1999. The increase in revenues was primarily attributable to
the increase in oil and gas prices in 2000. However, the Kansas properties oil
production increased in 2000 by 30,191 barrels and the Swan Creek oil production
increased by 25,317 barrels in 2000.
The Company's production costs and taxes have increased each year
from 1999 to 2001 as additional cost has been incurred to maintain the Kansas
wells and also to begin production from the Swan Creek Field for the first time
in 2001. The 2001 increase of $337,332 as compared to 2000 is due primarily to
the commencement of production from the Swan Creek Field. Production costs and
taxes only increased $49,482 from 1999 to 2000.
Depletion, depreciation, and amortization increased significantly in
2001 over 2000 and 1999 levels. The primary increase is due to significant
increases in depletion expense during 2001 ($1,142,000) as a result of the
following: decreases in reserve estimates on oil and gas properties arising from
declining commodity prices; certain of the Company's gas wells had decreased
production levels at year-end due to problems encountered with liquids in the
wells. This decreased production level at year-end was factored into the
estimated future proved reserves calculation performed as of December 31, 2001,
resulting in a lower future proved reserves estimate. Additionally, the Company
took depreciation on the pipeline for the first time in 2001 ($220,371). The
depletion, depreciation and amortization increased from $233,807 in 1999 to
$371,249 in 2000. The increase was due to depreciation on new equipment
purchased late in the years of 1999 and an increase in depletion expense of
$97,000 due to a change in estimate resulting from changes in reserves.
General and administrative expenses have increased from $1,961,348
in 1999 to $2,602,311 in 2000, to $2,957,871 in 2001. The increases from 2000 to
2001 are attributable to an increase in insurance (approximately $400,000) to
expand coverage including blowout insurance and the addition of Company
providing medical insurance for employees in 2001. The increase of $640,963 from
1999 to 2000 was due primarily to an increase in additional personnel,
consultants and increased engineering services for reserve evaluations.
Interest expense for 2001 increased significantly over 1999 and 2000
levels. This increase is due to additional interest cost associated with
financing for the completion of Phase II of the Company's 65 mile pipeline. This
increase was reduced by interest cost of approximately $148,000 which was
capitalized in the first 3 months of 2001 during construction of the pipeline
and $128,000 in 2000. Interest expense remained consistent from 1999 to 2000.
Public relations cost increased ($187,253) in 2001 as compared to
2000 levels due to cost associated with producing the annual report, the proxy
statement, and press releases. Public relations cost in 2000 was only slightly
higher ($20,134) than 1999 cost.
36
Professional fees decreased in 2001 from 2000 levels and are
consistent with 1999 levels due to a charge in 2000 of $242,000 for stock
options issued in 2000 to non-employees.
Dividends on preferred stock has increased from $119,347 in 1999 to
$257,557 in 2000 to $391,183 in 2001 as a result in the increase in preferred
stock outstanding.
LIQUIDITY AND CAPITAL RESOURCES
On November 8, 2001, the Company signed a credit facility agreement
(the "Credit Agreement") with the Energy Finance Division of Bank One, N.A. in
Houston Texas ("Bank One") whereby Bank One extended to the Company a revolving
line of credit of up to $35 million. The interest rate on the line of credit is
the Bank One base rate plus one quarter percent which at the time of closing was
5.25%. The initial borrowing base under the Credit Agreement was $10 million.
The initial borrowing base was determined by Bank One according to its own
internal and unspecified formulas. Under the terms of the Credit Agreement, the
initial borrowing base is to be reviewed and updated periodically by Bank One
based on its review, at various specified times, of reserve analyses of the
Company's proved oil and gas reserves, such as the report prepared by Ryder
Scott as of December 31, 2001. See, "Item 2 Description of Property - Reserve
Analysis." No increase will occur beyond the initial borrowing base of $10
million unless the Company's proved oil and gas reserves increase to such a
level that Bank One in its sole discretion according to its own internal
formulas determines that such an increase in the credit facility is warranted.
Conversely, the initial credit base may be decreased if Bank One upon review of
reserve analysis at times as specified in the Credit Agreement in its sole
discretion, according to its own internal formulas, determines that such a
decrease in the credit facility is warranted. In addition, the terms of the
Credit Agreement provides that the calculation of the borrowing base includes an
"equity cushion," in an unspecified amount, intended to protect Bank One from
difficulties in evaluating, liquidating, or collecting against oil and gas
properties stated to be subject to rapid deterioration in value and inherently
incapable of being accurately evaluated.
On November 9, 2001, funds from the Bank One credit line were used
to (1) satisfy existing indebtedness on the Company's Kansas Properties
($1,427,309.25); (2) repay the internal financing provided by Directors and
shareholders of the Company for the completion of the Company's 65 mile
intrastate pipeline ($3,895,490.83); (3) prepay a note due to Spoonbill, Inc.
for funds borrowed by the Company for working capital ($1,080,833.34); (4)
prepay a note due to Malcolm E. Ratliff, the Company's Chief Executive Officer,
for purchase by the Company of a drilling rig and related equipment
($1,003,844.44); and, (5) prepay the remaining balance of a loan made to the
Company for working capital by Edward W.T.Gray III, a former Director of the
Company, due on December 31, 2001 ($304,444.44). All of these obligations
incurred interest at a rate substantially greater than the rate being charged by
Bank One under the Credit Agreement. Together with attorneys fees, mortgage
taxes in Tennessee and Kansas and related fees the total drawn down on November
9, 2001 from the credit facility was $7,901,776.65. As of the date of this
Report, the principal balance of the loan under the Credit Agreement is
$9,101,776.66.
37
On or about April 5, 2002, the Company received a notice from Bank
One stating that it had re-determined and reduced the borrowing base under the
Credit Agreement to $3,101,766.66. The notice did not provide any explanation
why the reduction was made or as to how the reduction was calculated. As a
result of the reduction of the borrowing base, Bank One has demanded that the
Company satisfy the difference between the principal balance of the loan under
the Credit Agreement ($9,101,776.66) and the newly reduced current borrowing
base ($3,101,776.66) within thirty days of the receipt of the notice advising
the Company of the reduction of the borrowing base.
The Company has notified Bank One that it strongly disagrees that
the re-determination of the borrowing base was proper under the terms of the
Credit Agreement. It is the contention of the Company that a re-determination of
the borrowing base can only be made in accordance with specific schedules
provided for in the Credit Agreement. The Company is required to submit its
first analysis of proved reserves to Bank One by December 1, 2002 for purposes
of determining the borrowing base. Thereafter, reserve analysis are to be
reviewed every six months. The schedule of reserve reports required by the
Credit Agreement upon which such re-determinations are to be based also
specifically sets up a procedure involving an automatic monthly payment of
$200,000 effective as of February 1, 2002 to be applied against the borrowing
base.
The re-determination of the borrowing base made on April 5, 2002 by
Bank One is not in accordance with the expressed schedule in the Credit
Agreement which provides that the next re-determination date is after December
1, 2002, and which would allow for updated reserve analysis reports reflecting
the attendant adjustments to the Company's proved reserves as new wells come
into production and existing wells are re-worked in its Swan Creek Field before
any re-determination of the borrowing base could be made. Such updated reserve
analysis reports also would reflect the substantial current increases in oil and
gas prices from the substantially lower year-end oil and gas prices used to
evaluate the Company's reserves in the Company's most recent reserve analysis
report prepared by Ryder Scott as of December 31, 2001. The borrowing base
provisions of the Credit Agreement also permit Bank One to require the Company
to provide an analysis by certified engineers on ninety days notice if it has
concerns regarding the status of the reserves of the producing properties. This
was not done. Such a procedure would be the proper way for Bank One to have
proceeded if it had such concerns. Finally, the Company views Bank One's
position under the Credit Agreement to be fully secured by the properties the
Company owns in Kansas and Tennessee. The values of these properties far exceeds
the original initial borrowing base under the Credit Agreement. This fact
further underscores the impropriety of the attempted recent reduction of the
borrowing base and that such action is clearly unjustified by the terms and
intent of the Credit Agreement. The Company is seeking to have Bank One withdraw
its April 5, 2002 re-determination of the borrowing base.
In an effort to resolve this dispute amicably, alternatively, the
Company has requested Bank One to allow it to reduce the difference between the
principal balance of the loan and the reduced borrowing base over a period of
time. If the Company's request is honored, it is believed that through a
combination of the use of the Company's cash flow and outside equity or
38
loan financing it will be able to resolve any disputes with Bank One. However,
any substantial increase of the pay down of the loan over the $200,000 per month
presently being paid will significantly impair the Company's ability to repair
its current problem wells and to drill new wells. In the event the Company is
unable to resolve its differences with Bank One, the Company might be held to be
in default of its obligation to Bank One, which would enable Bank One to call
the entire loan. In such event, the Company would vigorously oppose any such
action by Bank One. If Bank One should be successful, the Company believes that
it would be able to procure alternative debt financing and equity funding to
enable to meet its obligation. The Company is hopeful that it will be able to
work out a satisfactory arrangement with Bank One.
Even if the Company is able to reach an agreement with Bank One as
to the amount of its current borrowing base and the pay-off of any difference
between that borrowing base and the principal balance of the loan, unless the
Company is able to increase production from its Swan Creek Field and as a
result, increase the calculation of proven oil and gas reserves it will not be
able to increase its borrowing base under the Bank One Credit Agreement beyond
the initial $10 million borrowing base. Although the Company is hopeful it will
be able to increase production and its proven reserves, there are no assurances
that the Company will be able to do so to an amount sufficient to allow it to
borrow additional sums from Bank One beyond the current borrowing base. In the
event that the Company is unable to increase the amount of its current borrowing
base under the Bank One Credit Agreement, it will be forced to seek other
options to obtain the funding necessary to meet its obligation to reduce the
Bank One loan and to satisfy all of its current and future cash requirements,
including funds necessary to re-work existing wells and continue the drilling
program in the Swan Creek Field. Such options would include debt financing, sale
of equity interests in the Company, a joint venture arrangement, the sale of oil
and gas interests, etc. The inability of the Company to obtain the necessary
cash funding on a timely basis would have an unfavorable effect on the Company's
financial condition and would require the Company to materially reduce the scope
of its operating and investing activities.
The Company plans to shortly offer for sale by private placement a
new series of cumulative convertible preferred stock. The additional capital
raised from such offering will be used to provide funds for re-payment to Bank
One of the Loan Excess, to pay for re-working of wells and continuing the
drilling program in the Swan Creek Field to increase production and to provide
working capital. There can be no assurances that the Company will be able to
sell such preferred stock or, if it is able to do so, the proceeds of the sale
of the new series of cumulative convertible preferred stock will be sufficient
to accomplish these purposes.
As a result of Bank One's reduction of the borrowing base and the
corresponding demand for payment of the difference between the amount of the
balance of the loan and the reduced borrowing base, combined with the fact that
the Company is still in the early stages of its oil and gas operating history
during which time it has a history of losses from operations and has an
accumulated deficit of $24,115,382 and a working capital deficit of $6,326,204
as of December 31, 2001, the Company's independent certified public accountants
have indicated in their report on the Consolidated Financial Statements that
these circumstances contribute to uncertainty over the Company's ability to
continue as a
39
going concern. The Company's ability to continue as a going concern depends upon
its ability to obtain long-term debt or raise capital to satisfy its cash flow
requirements. See, "Report of Independent Auditors" and "Notes to Consolidated
Financial Statements - Note 2 - Going Concern Uncertainty." Management believes
based upon the Company's substantial assets and proved reserves; its expectation
that production and revenues from its Swan Creek Field will increase by the end
of fiscal 2002; and, the current increase in oil and gas prices, that the
Company will be able to obtain the long-term debt or raise capital to enable it
to continue in business.
As of December 31, 2001, the Company had total stockholders' equity
of $14,991,847 on total assets of $32,128,245. The Company has a net working
capital deficiency at December 31, 2001 of $6,326,204 as compared to a net
deficiency of $708,317 at December, 2000. This working capital deficiency arises
primarily from the acceleration of $6,000,000 of the credit facility debt
discussed above.
Net cash used in operating activities decreased from $820,615 in
2000 to $221,176 in 2001. The Company's net loss in 2001 increased to $2,262,787
from $1,541,884 in 2000. The impact on cash used due to the net loss for 2001
was primarily offset by non-cash depletion, depreciation and amortization of
$1,849,963 and non-cash compensation and services paid by issuance of equity
instruments of $92,253. Cash flow from working capital items in 2001 was
$232,338 as compared to $66,020 in 2000. This resulted from increases in
accounts payable of $191,702, and decreases in inventory of 91,981 and accounts
receivable of $3,814, partially offset by a decrease in accrued interest payable
of $2,519 and a decrease in accrued liabilities of $52,640. Net cash used in
operating activities decreased from $2,587,003 in 1999 to $820,615 in 2000. This
was primarily due to the fact that the Company's net loss in 2000 decreased to
$1,541,884 from a net loss in 1999 of $2,671,923. The impact on cash used due to
the net loss for 2000 was partially offset by non-cash depletion, depreciation
and amortization of $371,249 and non-cash compensation and services paid by the
issuance of equity instruments of $284,000. Cash flow from working capital items
in 2000 was $66,020 as compared to uses of cash flow of $353,387 in 1999. This
reflects increases in accounts payable of $364,553 and accrued interest payable
of $135,435, partially offset by an increase in accounts receivable of $301,421,
and a decrease in other accrued liabilities of $140,955.
Net cash used in investing activities amounted to $9,408,684 for
2001 as compared to $8,936,863 for 2000. The large increase in net cash used for
investing activities during 2001 was primarily attributable to additions to oil
and gas properties of $4,821,883 in 2001 as compared to $1,456,996 in 2000. This
was offset by a reduction in expenditures used for the construction of Phase II
of the pipeline of $4,213,095 due to its completion in 2001 compared to
$6,834,196 in 2000 and a reduction of expenditures used for additions to other
property and equipment of $285,722 in 2001 as compared to $1,276,783 in 2000.
Net cash used in investing activities amounted to $8,936,863 for
2000 compared to net cash used in the amount of $1,892,294 for 1999. The large
increase in net cash used for
40
investing activities during 2000 was primarily attributable to the construction
of Phase II of the pipeline of $6,834,196 in 2000 as compared to $193,633 in
1999, additions to oil and gas properties of $1,456,996 in 2000 as compared to
$788,029 in 1999 and additions to other property and equipment of $1,276,783 in
2000 as compared to $256,045 in 1999.
Net cash provided by financing activities amounted to $8,419,336 in
2001 as compared to $ 10,940,863 in 2000. The primary sources of financing
include proceeds from borrowings of $10,442,068 in 2001 as compared to
$6,493,563 in 2000, private placements of common stock of $3,900,000 in 2001 as
compared to $4,425,713 in 2000, convertible redeemable preferred stock of
$1,591,150 in 2001 as compared to $2,000,000 in 2000 and proceeds from exercise
of options of $2,341,000 in 2001 as compared to $180,013 in 2000. The primary
use of cash in financing activities was the repayment of borrowings of
$8,833,325 in 2001 as compared to $1,720,856 in 2000.
Net cash provided by financing activities amounted to $10,940,863
for 2000 as compared to $3,896,693 for 1999. The primary sources of financing
include proceeds from borrowings of $6,493,563 in 2000 as compared to $2,119,023
in 1999, private placements of common stock of $4,425,700 in 2000 as compared to
$2,771,722 in 1999 and convertible redeemable preferred stock of $2,000,000 in
2000 as compared to $1,188,900 in 1999. The primary use of cash in financing
activities was the repayment of borrowings of $1,720,856 in 2000 as compared to
$2,383,605 in 1999.
CRITICAL ACCOUNTING POLICIES
The Company's accounting policies are described in the Notes to
Consolidated Financial Statements in Item 8 of this Report. The Company prepares
its Consolidated Financial Statements in conformity with accounting principles
generally accepted in the United States of America, which requires the Company
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the year. Actual results could differ from those estimates. The Company
considers the following policies to be the most critical in understanding the
judgments that are involved in preparing the Company's financial statements and
the uncertainties that could impact the Company's results of operations,
financial condition and cash flows.
CONTINGENCIES
The Company accounts for contingencies in accordance with Financial
Accounting Standards Board Statement of Financial Accounting Standards ("SFAS")
No. 5, "Accounting Contingencies." SFAS No. 5 requires that we record an
estimated loss from a loss contingency when information available prior to the
issuance of the Company's financial statements indicate that it is probable an
asset has been impaired or a liability has been incurred at the date of the
41
financial statements and the amount of the loss can be reasonably estimated.
Accounting for contingencies such as environmental, legal and income tax matters
requires management of the Company to use its judgment. While management of the
Company believes that the Company's accrual for these matters are adequate, if
the actual loss from a loss contingency is significantly different from the
estimated loss, the Company's results of operations may be over or understated.
The primary area in which the Company has to estimate contingent liabilities is
with respect to legal actions brought against the Company. See. Item 3 - Legal
Proceedings."
FULL COST METHOD OF ACCOUNTING
The Company follows the full cost method of accounting for oil and
gas property acquisition, exploration and development activities. Under this
method, all productive and non-productive costs incurred in connection with the
acquisition of, exploration for and development of oil and gas reserves for each
cost center are capitalized. Capitalized costs include lease acquisitions,
geological and geophysical work, daily rentals and the costs of drilling,
completing and equipping oil and gas wells. The Company capitalized $4,821,883,
$1,456,996 and $788,029 of these costs in 2001, 2000 and 1999, respectively.
Costs, however, associated with production and general corporate activities are
expensed in the period incurred. Interest costs related to unproved properties
and properties under development are also capitalized to oil and gas properties.
Gains or losses are recognized only upon sales or dispositions of significant
amounts of oil and gas reserves representing an entire cost center. Proceeds
from all other sales or dispositions are treated as reductions to capitalized
costs.
OIL AND GAS RESERVES
The capitalized costs of oil and gas properties, plus estimated
future development costs relating to proved reserves and estimated costs of
plugging and abandonment, net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The costs of unproved
properties are excluded from amortization until the properties are evaluated,
subject to an annual assessment of whether impairment has occurred.
The Company's proved oil and gas reserves as at December 31, 2001
were estimated by Ryder Scott, L.P., Petroleum Consultants. The Company's
discounted present value of its proved oil and gas reserves requires subjective
judgments. Estimates of the Company's reserves are in part forecasts based on
engineering data, projected future rates of production and timing of future
expenditures. The process of estimating oil and gas reserves requires
substantial judgment, resulting in imprecise determinations, particularly for
new discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. The passage of time provides more
qualitative information regarding estimates of reserves and revisions are made
to prior estimates to reflect updated information. Given the volatility of oil
and gas prices, it is also reasonably possible that the Company's estimate of
discounted net cash flows from proved oil and gas reserves could change in the
near term. If oil and gas prices decline
42
significantly as they did in 2001, this will result in a reduction of the
valuation of the Company's reserves. This past year, Ryder Scott based on
initial production results and the sharp decline of oil and gas prices,
significantly reduced the Company's estimated reserves of gas in the Swan Creek
Field from its reserve report for the year ended December 31, 2000. See, "Item 2
- - Description of Property - Reserve Analysis".
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standard
("SFAS") No. 133, "Accounting for Derivatives and Hedging Activities," effective
January 1, 2000. SFAS No. 133 ( as amended, by SFAS No. 137 and No. 138)
requires a company to recognize all derivatives on the balance sheet at fair
value. Derivatives that are not hedges must be adjusted to fair value through
income. If the derivative is a fair value hedge, changes in the fair value of
the hedged assets, liabilities or firm commitments are recognized through
earnings. If the derivative is a cash flow hedge the effective portion of
changes in the fair value of the derivative are recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value is immediately
recognized in earnings. The adoption of SFAS no. 133, as amended, did not have a
material impact on the Company's consolidated financial statements for the year
ending December 31, 2001.
In July 2001, the Financial Accounting Standards Board issued SFAS
No. 141, "Business Combinations" and SFAS No.142, "Goodwill and Other Intangible
Assets". SFAS No. 141 addresses the initial recognition and measurement of
goodwill and other intangible assets acquired in a business combination and SFAS
No. 142 addresses the initial recognition and measurement of intangible assets
acquired outside of a business combination whether acquired individually or with
a group of other assets. These standards require all future business
combinations to be accounted for using the purchase method of accounting.
Goodwill will no longer be amortized but instead will be subject to impairment
tests at least annually. The Company would have been required to adopt SFAS No.
141 on July 1, 2001, and to adopt SFAS 142 on a prospective basis as of January
1, 2002. The Company has not effected a business combination and carries no
goodwill on its balance sheet; accordingly, the adoption of these standards is
not expected to have an effect on the Company's financial position or results of
operations.
In June 2001, the Financial Accounting Standards Board approved the
issuance of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS
143 establishes accounting standards for the recognition and measurement of
legal obligations associated with the retirement of tangible long-lived assets
and requires recognition of a liability for an asset retirement obligation in
the period in which it is incurred. The provisions of this statement are
effective for financial statements issued for fiscal years beginning after June
15, 2002. The adoption of this statement is not expected to have a material
impact on the Company's financial position or results of operations.
43
SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, addresses accounting and reporting for the impairment or
disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of. SFAS No. 144 establishes a single accounting model for long-lived assets to
be disposed of by sale and expands on the guidance provided by SFAS No. 121 with
respect to cash flow estimations. SFAS No. 144 becomes effective for the
Company's fiscal year beginning January 1, 2002. There will be no current impact
of adoption on its financial position or results of operations.
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
COMMODITY RISK
The Company's major market risk exposure is in the pricing
applicable to its oil and gas production. Realized pricing is primarily driven
by the prevailing worldwide price for crude oil and spot prices applicable to
natural gas production. Historically, prices received for oil and gas production
have been volatile and unpredictable and price volatility is expected to
continue. Monthly oil price realizations ranged from a low of $14.00 per barrel
to a high of $27.73 per barrel during 2001. Gas price realizations ranged from a
monthly low of $1.68 per Mcf to a monthly high of $9.80 per Mcf during the same
period.
The Company entered into hedge agreements on December 28, 2001 on
notional volumes of oil and natural gas production for the first seven months of
2002 in order to manage some exposure to oil and gas price fluctuations.
Realized gains or losses from the Company's price risk management activities
will be recognized in oil and gas production revenues when earned since the
Company's positions are not considered hedges for financial reporting purposes.
Notional volumes associated with the Company's derivative contracts are 27,000
barrels and 630,000 MMBtu's for oil and natural gas, respectively. As these
activities are not effective until fiscal 2002, no gains or losses were
recognized for the year ended December 31, 2001. The Company does not generally
hold or issue derivative instruments for trading purposes.
At December 31, 2001, the Company's open natural gas and crude oil
price swap positions are not considered to have a material fair value. Assuming
natural gas production and sales volumes remain consistent at December 2001
levels during the entire year of fiscal 2002, management believes that a 10
percent decrease in unhedged natural gas prices would reduce the Company's
natural gas revenues by approximately $41,610 on an annual basis. Assuming crude
oil production and sales volumes remain consistent at December 2001 levels
during the entire year of fiscal 2002, management believes that a 10 percent
decrease in unhedged crude oil prices would reduce the Company's crude oil
revenues by approximately $208,840 on an annual basis.
44
INTEREST RATE RISK
At December 31, 2001, the Company had debt outstanding of
approximately $10.3 million. The interest rate on the revolving credit facility
of $9.1 million is variable based on the financial institution's prime rate plus
0.25%. The remaining debt of $1.2 million has fixed interest rates ranging from
7.5% to 11.95%. As a result, the Company's annual interest costs in 2002 would
fluctuate based on short-term interest rates on approximately 88% of its total
debt outstanding at December 31, 2001. The impact on interest expense and the
Company's cash flows of a 10 percent increase in the financial institution's
prime rate (approximately .5 basis points) would be approximately $45,500,
assuming borrowed amounts under the credit facility remain at $9.1 million. The
Company did not have any open derivative contracts relating to interest rates at
December 31, 2001.
FORWARD-LOOKING STATEMENTS AND RISK
Certain statements in this report, including statements of the
future plans, objectives, and expected performance of the Company, are
forward-looking statements that are dependent upon certain events, risks and
uncertainties that may be outside the Company's control, and which could cause
actual results to differ materially from those anticipated. Some of these
include, but are not limited to, the market prices of oil and gas, economic and
competitive conditions, inflation rates, legislative and regulatory changes,
financial market conditions, political and economic uncertainties of foreign
governments, future business decisions, and other uncertainties, all of which
are difficult to predict.
There are numerous uncertainties inherent in estimating quantities
of proved oil and gas reserves and in projecting future rates of production and
the timing of development expenditures. The total amount or timing of actual
future production may vary significantly from reserves and production estimates.
The drilling of exploratory wells can involve significant risks, including those
related to timing, success rates and cost overruns. Lease and rig availability,
complex geology and other factors can also affect these risks. Additionally,
fluctuations in oil and gas prices, or a prolonged period of low prices, may
substantially adversely affect the Company's financial position, results of
operations and cash flows.
ITEM 8 FINANCIAL STATEMENTS
The financial statements and supplementary data commence on page
F-1.
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable
45
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
IDENTIFICATION OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the names of all current directors
and executive officers of the Company. These persons will serve until the next
annual meeting of stockholders (to be held at such time as the Board of
Directors shall determine) or until their successors are elected or appointed
and qualified, or their prior resignations or terminations.
Date of Initial
Positions Election or
Name Held Designation
- ------------------- -------- -------
Joseph E. Armstrong Director 3/13/97
4708 Hilldale Drive
Knoxville, TN 37914
Benton L. Becker Director 8/31/99
1497 Lacosta Drive East
Pembrook Pines, FL 33027
Bill L. Harbert Director 4/2/02
820 Shaders Creek Pkway
Birmingham, AL 35209
Robert D. Hatcher, Jr Director 8/8/00
107 Golden Gate Lane
Oak Ridge, TN 37830
Malcolm E. Ratliff Chairman of the 4/21/98
2100 Scott Lane Board; Chief Executive
Knoxville, TN 37922 Officer
Charles Stivers Director 9/28/01
420 Richmond Road
Manchester, KY 40962
Harold G. Morris, Jr President 10/19/99
153 Chuniloti Way
Loudon, TN 37774
46
Mark A. Ruth Chief Financial 12/14/98
9400 Hickory Knoll Lane Officer
Knoxville, TN 37922
Robert M. Carter President Tengasco 6/1/98
760 Prince George Parish Drive Pipeline Corporation
Knoxville, TN 37931
Cary V. Sorensen General Counsel; 07/9/99
509 Bretton Woods Dr. Secretary
Knoxville, TN 37919
Sheila Sloan Treasurer 12/4/96
121 Oostanali Way
Loudon, TN 37774
Jeffrey R. Bailey Chief Geological 3/1/02
2306 West Gallaher Ferry Engineer
Knoxville, TN 37932
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
In fiscal 2001, Joseph Armstrong and Benton L. Becker, who are
Directors of the Company, each failed to timely file one Form 4 Report each
involving one transaction. Sanford E. McCormick who was a Director of the
Company until March 15, 2001 also failed to timely file one Form 4 Report
involving one transaction in 2001. In addition, Mr. Becker, as well as Robert D.
Hatcher, Jr., also a Director of the Company, each timely filed a Form 5 Report
for December 2001 which each reported one transaction that should have been
reported on an earlier Form 4 Report. Harold G. Morris, Jr., President of the
Company filed a Form 4 Report in 2001 that inadvertently was not filed in 1999
reporting one transaction. Malcolm E. Ratliff, the Company's Chief Executive
Officer and a Director of the Company, recently filed a timely Form 5 Report for
December 2001 which indicated that he failed to timely file eight Form 4 Reports
for 2001 involving 46 transactions. Mr. Ratliff also recently filed a Form 5
Report for December 2000 which should have been filed in 2001 indicating he had
failed to timely file five Form 4 Reports that were to be filed in 2000
involving 26 transactions. These deficiencies have all been cured.
BUSINESS EXPERIENCE
DIRECTORS
Joseph Earl Armstrong is 45 years old and a resident of Knoxville,
Tennessee. He is a graduate of the University of Tennessee and Morristown
College where he received a Bachelor of Science Degree in Business
Administration. From 1988 to the present, he has been an
47
elected State Representative for Legislative District 15 in Tennessee. From 1994
to the present he has been in charge of government relations for the Atlanta
Life Insurance Co. From 1981 to 1994 he was a District Manager for the Atlanta
Life Insurance Co.
Benton L. Becker is 64 years old. In 1960 he received a B.A. degree
from the University of Maryland. In 1966 he graduated from the American
University Law School in Washington, D.C. He is currently engaged in the private
practice of law in Coral Gables, Florida and Washington D.C., while regularly
serving as a Distinguished Lecturer on constitutional law at the University of
Miami in Coral Gables, Florida. His past positions include serving as a trial
attorney for the U. S. Department of Justice, the Dade County, Florida State's
Attorney Office and a Professor of Law at the University of Miami School of Law.
During his career Mr. Becker has represented the U.S. House of Representatives,
the Republican National Committee and President Gerald R. Ford. In 1976 Mr.
Becker represented Commonwealth Oil and Refining Company of Puerto Rico in a
Federal trial and Appellate action against Texaco, Exxon and Mobil and obtained
a multi-million dollar judgment for Commonwealth Oil. In 1980 he served as Board
Chairman for Appalachian Oil and Gas. From June 5, 1995 to January 30, 1997 he
served as Chairman of the Company's Board of Directors.
Bill L. Harbert is 78 years old. He earned a B.S. degree in civil
engineering from Auburn University in 1948. In 1949 he was one of the founders
of Harbert Construction Company. He managed that company's construction
operations, both domestic and foreign, and served as its Executive
Vice-President until 1979. From 1979 until July, 1990 he served as President and
Chief Operating Officer and from July 1990 through December 1991 he served as
Vice Chairman of the Board of Harbert International, Inc. He then purchased a
majority of the international operations of Harbert International, Inc. and
formed Bill Harbert International Construction, Inc. He served as Chairman and
Chief Executive Officer of that corporation until retiring from the company in
2000. Mr. Harbert's companies built pipeline projects in the United States and
throughout the world. They also built many other projects including bridges,
commercial buildings, waste water treatment plants, airports, including an air
base in Negev, Israel and embassies for the United States government in, among
other places, Tel Aviv, Hong Kong, and Baku. Mr. Harbert has also served as
president (1979) and Director (1980) of the Pipe Line Contractors Association,
USA and for seven years as Director, Second Vice-President and First
Vice-President (2001-2002) of the International Pipe Line Contractors
Association. Mr. Harbert has been active in service to a variety of business
associations, charities and the arts in the Birmingham area for many years.
Robert D. Hatcher, Jr. is 61 years old. He earned B.A. and M.S.
degrees from Vanderbilt University in 1961 and 1962, with majors in geology and
chemistry and a minor in mathematics. He earned a Ph.D. degree in 1965 from the
University of Tennessee (Knoxville), in structural geology with a minor in
chemistry. Thereafter, he worked with Humble Oil and Refining Company (now Exxon
USA) for one year. In 1966 he accepted a faculty position at Clemson University
where he taught and conducted research in the Appalachians until 1978. In 1978
Dr. Hatcher moved to Florida State University where he stayed until 1980. He
then taught at the University of South Carolina until 1986. In 1986, Dr. Hatcher
accepted a chair as a University
48
of Tennessee/Oak Ridge National Laboratory Distinguished Scientist, which
position he currently maintains. He has served on the Council (Board of
Directors) of the Geological Society of America (a not-for-profit corporation)
from 1981-1983 and again from 1992-1994 when he served on the Executive
Committee and as President (1993). He is currently serving on the Board of
Trustees of the Geological Society of America Foundation. He served on the
Executive Committee of the American Geological Institute (a not-for-profit
corporation) from 1995-1997 and as President in 1996. He has also served on the
National Academy of Sciences Board on Radioactive Waste Management and on
several National Research Council, as well as on Federal Advisory Committees for
the Nuclear Regulatory Commission and the Department of the Interior. He served
as Science Advisor to South Carolina Governor Richard Riley for Off-Site
Disposal of Radioactive Waste from 1984 through 1986. He was honored in 1997 by
the I.C. White Award and in 1998 by being made an honorary citizen of West
Virginia, both recognizing his long-term contributions to Appalachian geology.
He is a Fellow in the American Association for the Advancement of Science. Dr.
Hatcher is the author of over 150 journal articles and several texts and
monographs, including a structural geology textbook which has been used in some
85 colleges and universities. He has also served as an Editor of the Geological
Society of America Bulletin.
Malcolm E. Ratliff is 54 years old. He attended the University of
Mississippi and since 1971 has been involved in the oil and gas business with 30
years of hand-on experience in drilling and development of oil and gas wells,
seismic studies and laying pipe onshore and offshore. Mr. Ratliff holds numerous
oil and gas investments in companies throughout the United States. In April,
1995 he was instrumental in the founding of the Company and served as a
consultant to the Company's Board of Directors. In March, 1997 he became the
Chief Executive Officer of the Company and also acted as interim President of
the Company until he resigned in March, 1998 for health reasons. On April 21,
1998 at the request of the Company's Board of Directors, Mr. Ratliff agreed to
return to the management of the Company as its Chief Executive Officer. He has
served as Chairman of the Company's Board of Directors since June 19, 1998.
Charles M. Stivers is 39 years old. He is a Certified Public
Accountant with 18 years accounting experience. In 1984 he received a B.S.
degree in accounting from Eastern Kentucky University. From 1983 through July
1986 he served as Treasurer and CEO for Clay Resource Company. From August 1986
through August 1989 he served as a senior tax and audit specialist for Gallaher
and Company. From September 1989 to date he has owned and operated Charles M.
Stivers, C.P.A., a regional accounting firm. The Firm specializes in the oil and
gas industry and has clients in eight states. The oil and gas work performed by
the Firm includes all forms of SEC audit work, SEC quarterly financial statement
filings, oil and gas consulting work and income tax services. The Firm has also
represented oil and gas companies with respect to Federal and State income tax
disputes in 15 states over the past 12 years. In September 2001, he was elected
as a director of the Company and is the chairman of the Company's audit
committee.
OFFICERS
Harold G. Morris, Jr. is 53 years old. In 1970 he received a B.S.
Degree in
49
accounting from St. Peter's College in Jersey City, New Jersey. He is a member
of the National Association of Certified Fraud Examiners. From 1970 to 1975 he
worked in New York, New York for Main LaFrentz & Co., Certified Public
Accountants where he was a senior auditor for the firm's largest client, CPC
International, Inc. He was in charge of International Worldwide Consolidation,
along with the translation of multi-national currencies (Asian, European and
Canadian) into dollars. His experience includes audits of many industries
including the audit of Wall Street brokerage firms. From 1975 to 1980 he worked
for Foster Wheeler Corporate headquarters in Livingston, New Jersey as Chief
Internal Auditor where he assisted in all corporate mergers and acquisitions.
During this time he was promoted to CEO and CFO of Copeland Systems, Inc. and
then Treasurer/Controller of Chemical Separations Corp. in Oak Ridge Tennessee,
both of which were wholly owned subsidiaries of Foster Wheeler. From 1980 to
1983, Mr. Morris was Group Controller of Macawber Engineering's U.S., Japan,
England and Australian operations. From 1985 to 1999 he was Controller/Ass't.
Secretary for W. J. Savage Co., Inc. in Knoxville, Tennessee. He joined the
Company as Vice-President of Finance on October 19, 1999. On August 8, 2000 he
was elected as Executive Vice-President of the Company and on August 1, 2001 he
was elected as President of the Company.
Mark A. Ruth is 43 years old. He is a certified public accountant
with 21 years accounting experience. He received a B.S. degree in accounting
with honors from the University of Tennessee at Knoxville. He has served as a
project controls engineer for Bechtel Jacobs Company, LLC; business manager and
finance officer for Lockheed Martin Energy Systems; settlement department head
and senior accountant for the Federal deposit Insurance Corporation; senior
financial analyst/internal auditor for Phillips Consumer Electronics
Corporation; and, as an auditor for Arthur Andersen and Company. From December
14, 1998 to August 31, 1999 he served as the Company's Chief Financial Officer.
On August 31, 1999 he was elected as a Vice-President of the Company and on
November 8, 1999 he was again appointed as the Company's Chief Financial
Officer.
Robert M. Carter is 65 years old. He attended Tennessee Wesleyan
College and Middle Tennessee State College between 1954 and 1957. For 35 years
he was an owner of Carter Lumber & Building Supply Company and Carter Warehouse
in Loudon County, Tennessee. He has been with the Company since 1995 and during
that time has been involved in all phases of the Company's business including
pipeline construction, leasing, financing, and the negotiation of acquisitions.
Mr. Carter was elected Vice-President of the Company in March, 1996, as
Executive Vice-President in April 1997 and on March 13, 1998 he was elected as
President of the Company. He served as President of the Company until he
resigned from that position on October 19,1999. On August 8, 2000 he again was
elected as President of the Company and served in that capacity until July 31,
2001. He has served as President of Tengasco Pipeline Corporation, a wholly
owned subsidiary of the Company, from June 1, 1998 to the present.
Cary V. Sorensen is 53 years old. He is a 1976 graduate of the
University of Texas School of Law and has undergraduate and graduate degrees
form North Texas State University and Catholic University in Washington, D.C.
Prior to joining the Company in July, 1999, he had been continuously engaged in
the practice of law in Houston, Texas relating to the energy industry
50
since 1977, both in private law firms and a corporate law department, most
recently serving for seven years as senior counsel with the litigation
department of Enron Corp. before entering private practice in June, 1996. He has
represented virtually all of the major oil companies headquartered in Houston
and all of the operating subsidiaries of Enron Corp., as well as local
distribution companies and electric utilities in a variety of litigated and
administrative cases before state and federal courts and agencies in five
states. These matters involved gas contracts, gas marketing, exploration and
production disputes involving royalties or operating interests, land titles, oil
pipelines and gas pipeline tariff matters at the state and federal levels, and
general operation and regulation of interstate and intrastate gas pipelines. He
has served as Legal Counsel of the Company since July 9, 1999 and as Secretary
of the Company since March 4, 2002.
Sheila F. Sloan is 46 years old. She graduated from South Lake High
School located in St. Clair Shores, Michigan in 1972. From 1981 to 1985 she
worked as a purchasing agent for Sequoyah Land Company located in Madisonville,
Tennessee. From 1990 to 1995 she managed the Form U-3 Weight Loss Centers in
Knoxville, Tennessee. She has been with the Company since January 1996. On
December 4, 1996 she was elected as the Company's Treasurer.
Jeffrey R. Bailey is 44 years old. He graduated in 1980 from New
Mexico Institute of Mining and Technology with a B.S. degree in Geological
Engineering. Upon graduation he joined Gearhart Industries as a field engineer
working in Texas, New Mexico, Kansas, Oklahoma and Arkansas. Gearhart Industries
later merged with Halliburton Company. In 1993 after 13 years working in various
field operations and management roles primarily focused on reservoir evaluation,
log analysis and log data acquisition he assumed a global role with Halliburton
as a Petrophysics instructor in Fort Worth Texas. His duties were to teach
Halliburton personnel and customers around the world log analysis, competition
technology and to review anayltical reservoir problems. In this role Mr. Bailey
had the opportunity to review reservoirs in Europe, Latin America, Asia Pacific
and the Middle East developing a special expertise in carbonate reservoirs. In
1997 he became technical manager for Halliburton in Mexico focusing on finding
engineering solutions to the production challenges of large carbonate reservoirs
in Mexico. He joined the Company as its Chief Geological Engineer on March 1,
2002.
COMMITTEES
The Company's Board has operating stock option, audit, compensation
and frontier exploration committees. In fiscal 2001 Messrs. Stivers, Becker and
Gray comprised the stock option committee. Messrs. Stivers, Hatcher and Gray
comprised the audit committee, Messrs. Armstrong, Becker and Gray were the
members of the compensation committee and Messrs. McCormick, Hatcher and
Armstrong comprised the frontier exploration committee. The Board also formed a
field safety committee consisting of members of the Board and Officers of the
Company. That committee in 2001 consisted of Messrs. Ratliff, Armstrong, Carter,
Sorensen and Jeffrey Brockman, the field supervisor for the Company's drilling
operations.
51
FAMILY RELATIONSHIPS
There are no family relationships between any of the present
directors or executive officers of the Company.
INVOLVEMENT IN CERTAIN LEGAL PROCEEDINGS
To the knowledge of management, during the past five years, no
present or former director, executive officer, affiliate or person nominated to
become a director or an executive officer of the Company:
(1) Filed a petition under the federal bankruptcy laws or any
state insolvency law, nor had a receiver, fiscal agent or similar
officer appointed by a court for the business or property of such
person, or any partnership in which he or she was a general partner
at or within two years before the time of such filing, or any
corporation or business association of which he or she was an
executive officer at or within two years before the time of such
filing;
(2) Was convicted in a criminal proceeding or named subject of a
pending criminal proceeding (excluding traffic violations and other
minor offenses);
(3) Was the subject of any order, judgment or decree, not
subsequently reversed, suspended or vacated, of any court of
competent jurisdiction, permanently or temporarily enjoining him or
her from or otherwise limiting his or her involvement in any type of
business, securities or banking activities;
(4) Was found by a court of competent jurisdiction in a civil
action, by the Securities and Exchange Commission or the Commodity
Futures Trading Commission to have violated any federal or state
securities law, and the judgment in such civil action or finding by
the Securities and Exchange Commission has not been subsequently
reversed, suspended, or vacated.
ITEM 11 EXECUTIVE COMPENSATION
The following table sets forth a summary of all compensation awarded
to, earned or paid to, the Company's Chief Executive Officer during fiscal years
ended December 31, 2001, December 31, 2000 and December 31, 1999. None of the
Company's other executive officers earned compensation in excess of $100,000 per
annum for services rendered to the Company in any capacity.
52
SUMMARY COMPENSATION TABLE
-----------LONG TERM AWARDS-----
ANNUAL COMPENSATION -----------AWARDS----PAYOUTS
====================================================================================================================================
Name and YEAR SALARY ($) BONUS ($) OTHER ANNUAL RESTRICTED SECURITIES PAYOUTS ALL OTHER
Principal Position COMPENSATION($) STOCK UNDERLYING COMPEN-
AWARDS($) OPTIONS /SARS(#) SATION
- ------------------------------------------------------------------------------------------------------------------------------------
Malcolm E. Ratliff, 2001 $ 80,000 $-0- $1,000 -0- 52,500(6) -0- -0-
Chief Executive Officer 2000 $ 70,000 $-0- $ 500 -0- 52,500 -0- -0-
1999 $ 60,000 $-0- $ 500 -0- 52,500 -0- -0-
====================================================================================================================================
- ----------
(1) Number of shares underlying options has been retroactively adjusted for a
5% stock dividend declared by the Company as of September 4, 2001. 1 Number of
shares underlying the unexercised options has been retroactively adjusted for a
5% stock dividend declared by the Company as of September 4, 2001.
53
OPTION GRANTS FOR FISCAL 2001
No options were granted during fiscal year ended December 31, 2001
to the Chief Executive Officer. None of the Company's other executive officers
earned compensation in excess of $100,000 per annum for services rendered to the
Company in any capacity during the fiscal year ended December 31, 2001.
AGGREGATE OPTION EXERCISES FOR FISCAL 2001
AND YEAR END OPTION VALUES
========================= =========================
NUMBER OF SECURITIES(7) VALUE(8) OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY
OPTIONS / SARS AT OPTIONS/SARS AT
DECEMBER 31, 2001 DECEMBER 31, 2001
======================== ================== ============
NAME SHARES ACQUIRED VALUE ($) EXERCISABLE/ EXERCISABLE/
ON EXERCISE REALIZED(9) UNEXERCISABLE UNEXERCISABLE
- ------------------------ ------------------ ------------ ------------------------- -------------------------
Malcolm E. Ratliff -0- -0- 52,500/-0- $-0-/-0-
======================== ================== ============ ========================= =========================
No options were exercised during fiscal year ended December 31, 2001
by the Chief Executive Officer. None of the Company's other executive officers
earned compensation in excess of $100,000 per annum for services rendered to the
Company in any capacity.
The Company adopted an employee health insurance plan in August
2001. The Company does not presently have a pension or similar plan for its
directors, executive officers or employees. Management intends to adopt a 401(k)
plan and full liability insurance for directors and executive officers in the
near future.
- ----------
(7) Number of shares underlying the unexercised options has been retroactively
adjusted for a 5% stock dividend declared by the Company as of September 4,
2001.
(8) Unexercised options are in-the-money if the fair market value of the
underlying securities exceeds the exercise price of the option. The fair market
value of the Common Stock was $8.28 per share on December 31, 2001, as reported
by The American Stock Exchange. The exercise price of the unexercised option
granted to Malcolm E. Ratliff, the Chief Executive Officer of the Company, is
$8.69 per share. As a result, the unexercised options have a negative value.
(9) Value realized in dollars is based upon the difference between the fair
market value of the underlying securities on the date of exercise, and the
exercise price of the option.
54
COMPENSATION OF DIRECTORS
The Board of Directors has resolved to compensate members of the
Board of Directors for attendance at meetings at the rate of $250 per day,
together with direct out-of-pocket expenses incurred in attendance at the
meetings, including travel. The Directors, however, have waived such fees due to
them as of this date for prior meetings.
Members of the Board of Directors may also be requested to perform
consulting or other professional services for the Company from time to time. The
Board of Directors has reserved to itself the right to review all directors'
claims for compensation on an ad hoc basis.
EMPLOYMENT CONTRACTS
The Company has entered into an employment contract with its Chief
Geological Engineer, Jeffrey R. Bailey for a period of one year through February
28, 2003 at an annual salary of $84,000. There are presently no other employment
contracts relating to any member of management. However, depending upon the
Company's operations and requirements, the Company may offer long term contracts
to directors, executive officers or key employees in the future.
COMPENSATION COMMITTEE INTERLOCKING
AND INSIDER PARTICIPATION
There are no interlocking relationship between any member of the Company's
Compensation Committee and any member of the compensation committee of any other
company, nor has any such interlocking relationship existed in the past. No
member of the Compensation Committee is or was formerly an officer or an
employee of the Company.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following tables set forth the share holdings of the Company's
directors and executive officers and those persons who own more than 5% of the
Company's common stock as of March 1, 2002 with these computations being based
upon 10,656,401 shares of common stock being outstanding as of that date and
assumes the exercise of 383,250 shares vested under options granted by the
Company as of March 1, 2002.
55
FIVE PERCENT STOCKHOLDERS(10)
NUMBER OF SHARES PERCENT
NAME AND ADDRESS TITLE BENEFICIALLY OWNED OF CLASS
- ---------------- ----- ------------------ --------
Industrial Resources Stockholder 2,823,987(11) 26.4%
Corporation
603 Main Ave
Knoxville, TN 37902
Spoonbill, Inc. Stockholder 878,198 8.24%
Tung Wai Commercial Bldg
20th Floor
109-111 Gloucester Rd
Wanchai, Hong Kong
Bill L. Harbert Stockholder/ 1,077,667 10.11%
820 Shaders Creek Pkwy Director
Birmingham, AL 35209
- ----------
(10) Unless otherwise stated, all shares of Common Stock are directly held with
sole voting and dispositive power. The shares set forth in the table reflect the
5% stock dividend declared by the Company for shareholders of record as of
September 4, 2001.
(11) Malcolm E. Ratliff, the Chief Executive Officer and Chairman of the Board
of Directors of the Company is the sole owner of the outstanding securities and
President of Industrial Resources Corporation (" IRC").Ownership of the IRC
shares was previously transferred from Malcolm E. Ratliff, due to his illness,
to his father, James Ratliff. In December 1999 ownership of the IRC shares was
transferred back to Malcolm E. Ratliff from his father. Malcolm E. Ratliff's
wife, Linda Ratliff, is the Secretary of IRC. Accordingly, IRC may be deemed to
be an affiliate of the Company. James Ratliff, who is the father of Malcolm E.
Ratliff, is the sole shareholder and President of Ratliff Farms, Inc. Malcolm E.
Ratliff is the Vice-President/Secretary of Ratliff Farms. Malcolm E. Ratliff has
voting control of the shares of the Company owned by Ratliff Farms, Inc.
Accordingly, Ratliff Farms, Inc. may also be deemed to be an affiliate of the
Company. The shares listed here for IRC include 2,299,744 shares owned directly
by IRC, 59,171 shares owned directly and an option to purchase 52,500 shares
held by Malcolm E. Ratliff, 381,072 shares owned directly by Ratliff Farms, Inc.
and 31,500 shares owned directly by a trust of which Linda Ratliff is trustee
and the children of Malcolm E. Ratliff are the beneficiaries. The shares listed
here do not include shares of the Company owned directly by James Ratliff.
56
DIRECTORS AND OFFICERS(12)
NUMBER OF SHARES PERCENT
NAME AND ADDRESS TITLE BENEFICIALLY OWNED OF CLASS
- ---------------- ----- ------------------ --------
Joseph Earl Armstrong Director 51,4502 Less than 1%
4708 Hilldale Drive
Knoxville, TN 37914
Benton L. Becker Director 73,7503 Less than 1%
1497 Lacosta Drive East
Pembrook Pines, FL 33027
Robert D. Hatcher, Jr Director 52,605(15) Less than 1%
107 Golden Gate Lane
Oak Ridge, TN 37830
Bill L. Harbert Director 1,077,667 10.11%
820 Shaders Creek Pkwy
Birmingham, AL 35209
Malcolm E. Ratliff Chief Executive 2,823,987(16) 26.4%
2100 Scott Lane Officer; Chairman
Knoxville, TN 37922 of the Board
- ----------
(12) Unless otherwise stated, all shares of Common Stock are directly held with
sole voting and dispositive power. The shares set forth in the table reflect the
5% stock dividend declared by the Company for shareholders of record as of
September 4, 2001.
(13) Consists of 9,450 shares held directly and an option to purchase 42,000
shares.
(14) Consists of 21,250 shares owned directly and an option to purchase 52,500
shares.
(15) Consists of 105 shares owned directly and an option to purchase 52,500
shares.
(16) Malcolm E. Ratliff, the Company's Chief Executive Officer and Chairman of
the Board of Directors, is also the sole shareholder and President of Industrial
Resources Corporation ("IRC"). Ownership of the IRC shares was previously
transferred from Malcolm E. Ratliff, due to his illness to his father, James
Ratliff. In December 1999 ownership of the IRC shares was transferred back to
Malcolm E. Ratliff from his father. Linda Ratliff, Malcolm E. Ratliff's wife, is
the Secretary of IRC.James Ratliff, who is the father of Malcolm E. Ratliff, is
the sole shareholder and president of Ratliff Farms, Inc. Malcolm E. Ratliff is
the Vice-President/Secretary of Ratliff Farms, Inc. Malcolm E. Ratliff has
voting control over the shares of the Company owned by Ratliff Farms, Inc. The
shares listed here include 2,299,744 shares owned directly by IRC, 59,171 shares
owned directly and an option to purchase 52,500 shares held by Malcolm E.
Ratliff, 381,072 owned directly by Ratliff Farms, Inc. and 31,500 shares owned
directly by a trust of which Linda Ratliff is trustee and the beneficiaries are
the children of Malcolm E. Ratliff (the "Ratliff Trust"). The shares listed here
do not include shares of the Company owned directly by James Ratliff.
57
Charles M. Stivers Director -0- -0-
420 Richmond Road
Manchester, KY 40962
Harold G. Morris, Jr President 61,817(17) Less than 1%
153 Chuniloti Way
Loudon, TN 37774
Robert M. Carter President 54,946(18) Less than 1%
760 Prince Georges Parish Tengasco Pipeline
Knoxville, TN 37922 Corporation
Mark A. Ruth Chief Financial 36,750(19) Less than 1%
9400 Hickory Knoll Lane Officer
Knoxville, TN 37931
Cary V. Sorensen General Counsel; 31,500(20) Less than 1%
509 Bretton Woods Dr. Secretary
Knoxville, TN 37919
Sheila F. Sloan Treasurer 17,850(21) Less than 1%
121 Oostanali Way
Loudon, TN 37774
Jeffrey R. Bailey Chief Geological -0- -0-
2306 West Gallaher Ferry Engineer
Knoxville, TN 37932
All Officers and 4,282,322(22) 38.8%
Directors as a group
- ----------
(17) Consists of 5,775 shares held directly, 3,542 shares owned by his wife and
an option to purchase 52,500 shares.
(18) Consists of 7,696 shares held directly and an option to purchase 47,250
shares.
(19) Consists of shares underlying an option.
(20) Consists of shares underlying an option.
(21) Consists of 2,100 shares held directly and an option to purchase 15,750
shares.
(22) Consists of shares held directly and indirectly by management, shares held
by IRC, shares held by Ratliff Farms, Inc., shares held by the Ratliff Trust and
383,250 shares underlying options.
58
CHANGES IN CONTROL
Except as indicated below, to the knowledge of the Company's
management, there are no present arrangements or pledges of the Company's
securities which may result in a change in control of the Company.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TRANSACTIONS WITH MANAGEMENT AND OTHERS
Except as set forth hereafter, there have been no material
transactions, series of similar transactions or currently proposed transactions,
to which the Company or any of its subsidiaries was or is to be a party, in
which the amount involved exceeds $60,000 and in which any director or executive
officer or any security holder who is known to the Company to own of record or
beneficially more than 5% of the Company's common stock, or any member of the
immediate family of any of the foregoing persons, had a material interest.
On January 24, 2001, the Stock Option Committee granted an
additional option pursuant to the Tengasco, Inc. Stock Incentive Plan to Shigemi
Morita, who at the time was a Director of the Company (he subsequently resigned
from that position on February 1, 2002 for personal reasons) to purchase 20,000
shares of the Company's common stock for a period of three years at a price of
$14.44 per share.
On November 8, 2001, the Company signed a credit facility with the
Energy Finance Division of Bank One, N.A. in Houston, Texas whereby Bank One
extended to the Company a revolving credit line of up to $35 million. The
initial borrowing base under the facility was $10 million. The balance of the
borrowing base is to be adjusted upon periodic review by Bank One based upon the
Company's oil and gas reserves. The interest rate is the Bank One base rate plus
one-quarter percent. On November 9, 2001, funds from the initial borrowing base
of $10 million were used by the Company to, among other things, repay the
internal financing provided by Directors and shareholders of the Company to
complete Phase II of the Company's pipeline in the aggregate amount of $3.85
million of which the sum of $500,000 was loaned by Morita Properties, Inc., an
affiliate of Shigemi Morita, who at the time was a Director of the Company,
$1,000,000 was loaned by Edward W.T. Gray III, a Director of the Company and
$250,000 was loaned by Malcolm E. Ratliff, Chairman of the Board of Directors
and Chief Executive Officer of the Company; prepay a purchase money note due to
Malcolm E. Ratliff issued in connection with the Company's purchase of a
drilling rig and related equipment from Mr. Ratliff in the amount of
$1,003,844.44; and, prepay in full the remaining principal of the working
capital loan due December 31, 2001 to Edward W.T.Gray III, a Director of the
Company, in the amount of $304,444.44. All of these obligations incurred
interest at a rate substantially greater than the rate
59
being charged by Bank One under the Credit Facility. See, "Item 7 - Liquidity
and Financial Condition."
In January 2001, Ratliff Farms, Inc. transferred 164,000 of its
shares in the Company to James Ratliff, its sole shareholder and President and
who is the father of Malcolm E. Ratliff. Malcolm E. Ratliff is the
Vice-President/Secretary of Ratliff Farms, Inc. and has voting control over the
shares of the Company owned by Ratliff Farms, Inc. He does not have voting
control over the shares of the Company owned by James Ratliff, nor are these
shares included in determining the number of shares controlled by Malcolm E.
Ratliff and/or Industrial Resources Corp. See, "Item 12 - Security Ownership of
Certain Beneficial Owners and Management."
INDEBTEDNESS OF MANAGEMENT
No officer, director or security holder known to the Company to own
of record or beneficially more than 5% of the Company's common stock or any
member of the immediate family of any of the foregoing persons is indebted to
the Company.
PARENT OF THE ISSUER
Unless IRC may be deemed to be a parent of the Company, the Company
has no parent.
PART IV
ITEM 14 EXHIBITS AND REPORTS
1. Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Loss
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
2. Exhibits.
(a) - The following documents heretofore filed by the Company with the
commission are hereby incorporated by reference herein from:
60
(i) Registration Statement on Form 10-SB filed with the Commission August 7,
1997 (Registration No. 0-29386)
Exhibit Number and Description
3.1 Initial Articles of Incorporation
3.2 Bylaws
3.3 Articles of Amendment dated April 12, 1966
3.4 Articles of Amendment dated July 12, 1984
3.5 Articles of Amendment dated December 18, 1991
3.6 Articles of Amendment dated September 11, 1992
3.7 Articles of Incorporation of the Tennessee of wholly-owned
subsidiary
3.8 Articles of Merger and Plan of Merger (taking into account the
formation of the Tennessee wholly-owned subsidiary for the
purpose of changing the Company's domicile and effecting
reverse split)
5.1 Opinion of Robson & Miller, LLP
10.1(a) Purchase Agreement with IRC
10.1(b) Amendment to Purchase Agreement with IRC
10.1(c) General Bill of Sale and Promissory Note
10.2(a) Compensation Agreement - M. E. Ratliff
10.2(b) Compensation Agreement - Jeffrey D. Jenson
10.2(c) Compensation Agreement - Leonard W. Burningham
10.3 Agreement with The Natural Gas Utility District of Hawkins
County, Tennessee
10.4 Agreement with Powell Valley Electric Cooperative, Inc.
10.5 Agreement with Enserch Energy Services, Inc.
16.1 Letter of David T. Thomson, CPA, Regarding Change in
Certifying Accountant
16.2 Letter of Charles M. Stivers, CPA, Regarding Change in
Certifying Accountant
16.3 Letter of Price-Bednar, LLP, CPA, Regarding Change in
Certifying Accountant
23.1 Consent of Charles M. Stivers, CPA
23.2 Consent of David T. Thomson, CPA
23.3 Consent of BDO Seidman, LLP
23.4 Consent of Robson & Miller, LLP
99.1 Beech Creek Lease Schedule
99.2 Wildcat Lease Schedule
99.3 Burning Springs Lease Schedule
99.4 Fentress County Lease Schedule
99.5 Swan Creek Lease Schedule
99.6 Alabama Lease Schedule
99.7 Coburn Engineering Report dated June 18, 1997.
61
(ii) Amendment No. 1 to the Registration Statement on Form 10-SB filed with the
Commission December 11, 1997 (Registration No. 0-29386)
Exhibit Number and Description
5.1 Opinion of Robson & Miller, LLP
23.1 Consent of Charles M. Stivers, CPA
23.3 Consent of BDO Seidman, LLP
23.4 Consent of Robson & Miller, LLP
23.5 Consent of Coburn Petroleum Engineering Co.
(iii) Current Report on Form 8-K, Date of Report, February 27, 1998:
Exhibit Number and Description
2.1 Plan of Acquisition. Agreement dated December 18, 1997 between
AFG Energy, Inc. and Tengasco, Inc. regarding sale of assets
of AFG Energy, Inc.
(iii) Current Report on Form 8-KA, Date of Report, February 27, 1998:
Exhibit Number and Description
Financial Statements of Business Acquired (AFG Energy, Inc.)
Independent auditor's report, statement of revenues and direct
operating expenses and notes to financial statements of the
properties acquired by Tengasco, Inc. from AFG Energy, Inc.
Pro Forma Financial Information Pro forma combined statements
of loss for year ended December 31, 1997 for Tengasco, Inc.
from AFG Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG
Energy, Inc. and Tengasco, Inc. regarding sale of assets of
AFG Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG
Energy, Inc. and Tengasco, Inc. regarding sale of assets of
AFG Energy, Inc.
(iv) Annual Report on Form 10-KSB, Date of Report, April 10, 1998
Exhibit Number and Description
10.6 Teaming Agreement between Operations Management International,
Inc. and Tengasco, Inc. dated March 12, 1997
10.7 Agreement for Transition Services between Operations
Management
62
International, Inc. and Tengasco, Inc. regarding thEast
Tennessee Technology Park
99.8 Coburn Engineering Report dated February 18, 1997 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
99.9 Columbia Engineering Report dated March 2, 1997 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
(v) Annual Report on Form 10-KSB, Date of Report, April 14, 1999
Exhibit Number and Description
3.9 Amendment to the Corporate Charter dated June 24, 1998
3.10 Amendment to the Corporate Charter dated October 30, 1998
99.10 Coburn Engineering Report dated February 9, 1999 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
99.11 Columbia Engineering Report dated February 20, 1999 (Paper
copy filed on Form SE pursuant to continuing hardship granted
by Office of EDGAR Policy)
(vi) Current Report on Form 8-K, Date of Report, October 18, 1999:
Exhibit Number and Description
10.9 Amendment Agreement dated October 19, 1999 between Tengasco,
Inc. and The Natural Gas Utility District of Hawkins County,
Tennessee
(vii) Current Report on Form 8-KA, Date of Report, November 18, 1999:
Exhibit Number and Description
10.10 Natural Gas Sales Agreement dated November 18, 1999 between
Tengasco, Inc. and Eastman Chemical Company
(viii) Annual Report on Form 10-KSB, Date of Report, April 12, 2000
Exhibit Number and Description
3.11 Amendment to the Corporate Charter filed March 17 , 2000
10.11 Agreement between A.M. Partners L.L.C. and Tengasco, Inc.
dated October 6, 1999
10.12 Agreement between Southcoast Capital L.L.C. and Tengasco, Inc.
dated February 25, 2000
63
10.13 Franchise Agreement between Powell Valley Utility District and
Tengasco, Inc. dated January 25, 2000
10.14 Amendment Agreement between Eastman Chemical Company and
Tengasco, Inc. dated March 27, 2000
99.12 Coburn Engineering Report dated March 30, 2000 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
99.13 Columbia Engineering Report dated January 31, 2000 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
(ix) Current Report on Form 8-K, Date of Report, August 16, 2000:
Exhibit Number and Description
10.15 Loan Agreement between Tengasco Pipeline Corporation and
Morita Properties, Inc. dated August 16, 2000.
10.15(a) Promissory note made by Tengasco Pipeline Corporation to
Morita Properties, Inc. dated August 16, 2000.
10.15(b) Throughput Agreement between Tengasco Pipeline Corporation and
Morita Properties, Inc. dated August 16, 2000.
10.16 Loan Agreement between Tengasco Pipeline Corporation and
Edward W.T. Gray III dated August 16, 2000.
10.16(a) Promissory note made by Tengasco Pipeline Corporation to
Edward W.T. Gray III dated August 16, 2000.
10.16(b) Throughput Agreement between Tengasco Pipeline Corporation and
Edward W.T. Gray III dated August 16, 2000.
10.17 Loan Agreement between Tengasco Pipeline Corporation and
Malcolm E. Ratliff dated August 16, 2000.
10.17(a) Promissory note made by Tengasco Pipeline Corporation to
Malcolm E. Ratliff dated August 16, 2000.
10.17(b) Throughput Agreement between Tengasco Pipeline Corporation and
Malcolm E. Ratliff dated August 16, 2000.
10.18 Loan Agreement between Tengasco Pipeline Corporation and
Charles F. Smithers, Jr. dated August 16, 2000.
64
10.18(a) Promissory note made by Tengasco Pipeline Corporation to
Charles F. Smithers, Jr.
10.18(b) Throughput Agreement between Tengasco Pipeline Corporation and
Charles F. Smithers dated August 16, 2000.
10.19 Loan Agreement between Tengasco Pipeline Corporation and Nick
Nishiwaki dated August 16, 2000.
10.19(a) Promissory note made by Tengasco Pipeline Corporation to Nick
Nishiwaki dated August 16, 2000.
10.19(b) Throughput Agreement between Tengasco Pipeline Corporation and
Nick Nishiwaki dated August 16, 2000.
(x) S-8 Registration Statement for shares to be purchased pursuant to options
granted pursuant to the Tengasco, Inc. Stock Incentive Plan dated October 25,
2000:
Exhibit Number and Description
4.1 Tengasco, Inc. Incentive Stock Plan
5.1 Opinion of Robson Ferber Frost Chan & Essner, LLP
23.1 Consent of BDO Seidman, LLP
23.2 Consent of Robson Ferber Frost Chan & Essner, LLP contained in
Exhibit No. 5.1
(xi) Annual Report on Form 10-KSB, Date of Report, April 10, 2001
Exhibit Number and Description
10.19 Memorandum Agreement between Tengasco, Inc. and The University
of Tennessee dated February 13, 2001
10.20 Natural Gas Sales Agreement between Tengasco, Inc. and BAE
SYSTEMS Ordnance Systems Inc. dated March 30, 2001
99.14 Ryder Scott Report
65
99.14(a) Consent of Ryder Scott Company
(xii) Quarterly Report on Form 10-Q, Date of Report, April 10, 2001
Exhibit Number and Description
10.21 Reducing Revolving Line of Credit Up to $35,000,000 from Bank
One, N.A. to Tengasco, Inc., Tennessee Land & Mineral
Corporation and Tengasco Pipeline Corporation dated November
8, 2001
The following exhibits are filed herewith:
99.15 Ryder Scott Report dated March 28, 2002
99.15(a) Consent of Ryder Scott Company
21 List of Subsidiaries
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities and
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Dated: April 19, 2002
TENGASCO, INC.
(Registrant)
By: s/ MALCOLM E. RATLIFF
---------------------
Malcolm E. Ratliff,
Chief Executive Officer
By: s/ MARK A. RUTH
---------------
Mark A. Ruth,
Principal Financial and Accounting Officer
66
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in their capacities and on the dates indicated.
Signature Title Date
s/ MALCOLM E. RATLIFF Chief Executive Officer; April 19, 2002
- ------------------------ Chairman of the Board
Malcolm E. Ratliff of Directors
s/ JOSEPH EARL ARMSTRONG Director April 18, 2002
- ------------------------
Joseph Earl Armstrong
s/ BENTON L. BECKER Director April 19, 2002
- ------------------------
Benton L. Becker
s/ BILL L. HARBERT Director April 19, 2002
- ------------------------
Bill L. Harbert
s/ ROBERT D. HATCHER, JR. Director April 18, 2002
- ------------------------
Robert D. Hatcher, Jr.
s/ CHARLES M. STIVERS Director April 19, 2002
- ------------------------
Charles M. Stivers
s/ HAROLD G. MORRIS, JR. President April 19, 2002
- ------------------------
Harold G. Morris, Jr.
s/ MARK A. RUTH Principal Financial April 19, 2002
- ------------------------ and Accounting Officer
Mark A. Ruth
67
TENGASCO, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
TENGASCO, INC.
AND SUBSIDIARIES
- --------------------------------------------------------------------------------
CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
F-1
TENGASCO, INC. AND SUBSIDIARIES
CONTENTS
- --------------------------------------------------------------------------------
INDEPENDENT AUDITORS' REPORT F-3
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance sheets F-4-5
Consolidated Statements of loss F-6
Consolidated Statements of stockholders' equity F-7-8
Consolidated Statements of cash flows F-9-10
Notes to consolidated financial statements F-11-37
F-2
Independent Auditors' Report
Board of Directors
Tengasco, Inc. and Subsidiaries
Knoxville, Tennessee
We have audited the accompanying consolidated balance sheets of Tengasco, Inc.
and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of loss, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Tengasco, Inc. and
Subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses from operations
and has an accumulated deficit of $24,115,382. Additionally, on April 5, 2002,
the Company's lender reduced its borrowing base under its revolving line of
credit agreement by $6,000,000, which amount has become immediately due and
payable resulting in a significant working capital deficiency. Such matters
raise substantial doubt about the Company's ability to continue as a going
concern. Management's plans in regard to these matters are also described in
Note 2. The financial statements do not include any adjustments that might
result from the outcome of this uncertainty.
Atlanta, Georgia
March 12, 2002, except for Note 2,
which is as of April 12, 2002
F-3
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
DECEMBER 31, 2001 2000
- ----------------------------------------------------------------------------------------------
ASSETS (Note 7)
CURRENT
Cash and cash equivalents $ 393,451 $1,603,975
Investments 150,000 --
Accounts receivable 661,475 684,132
Participant receivables 84,097 65,254
Inventory 159,364 251,345
- ----------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS 1,448,387 2,604,706
OIL AND GAS PROPERTIES, net (on the basis
of full cost accounting) (Notes 4, 7 and 15) 13,269,930 9,790,047
COMPLETED PIPELINE FACILITIES, net (Notes 5 and 7) 15,039,762 4,200,000
PIPELINE FACILITIES UNDER CONSTRUCTION, at cost (Note 5) -- 6,847,038
OTHER PROPERTY AND EQUIPMENT, net (Notes 6 and 7) 1,680,104 1,677,432
RESTRICTED CASH (Notes 1 and 8) 120,872 --
LOAN FEES, net of accumulated amortization of $21,590 496,577 --
OTHER 72,613 105,501
- ----------------------------------------------------------------------------------------------
$32,128,245 $25,224,724
- ----------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-4
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
DECEMBER 31, 2001 2000
- ----------------------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt - related party
(Notes 3 and 7) $ -- $ 500,000
Current maturities of long-term debt (Note 7) 6,399,831 1,608,486
Accounts payable - trade 1,208,164 1,016,462
Accrued interest payable 54,138 56,657
Accrued dividends payable 112,458 78,778
Other accrued liabilities -- 52,640
- ----------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 7,774,591 3,313,023
- ----------------------------------------------------------------------------------------------
LONG-TERM DEBT - RELATED PARTIES, less current
maturities (Notes 3 and 7) -- 4,845,000
LONG TERM DEBT, less current maturities (Note 7) 3,902,757 2,263,599
- ----------------------------------------------------------------------------------------------
Total long-term debt 3,902,757 7,108,599
- ----------------------------------------------------------------------------------------------
Total liabilities 11,677,348 10,421,622
- ----------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 2 and 8)
PREFERRED STOCK, $.0001 par value; authorized
25,000,000 shares (Note 9):
Series A 8% cumulative, convertible,
mandatorily redeemable; 28,679 and 29,389
shares outstanding; redemption value
$2,867,900 and $2,938,900 2,867,900 2,938,900
Series B 8% cumulative, convertible,
mandatorily redeemable; 27,550 and 1,000
shares outstanding; redemption value
$2,755,000 and $1,000,000, net of related
commissions 2,591,150 1,000,000
- ----------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK 5,459,050 3,938,900
- ----------------------------------------------------------------------------------------------
STOCKHOLDERS' EQUITY (Notes 10 and 11)
Common stock, $.001 par value; authorized
50,000,000 shares; 10,560,605 and 9,295,558
shares issued, respectively 10,561 9,296
Additional paid-in capital 39,242,555 25,941,709
Accumulated deficit (24,115,382) (15,086,803)
Treasury Stock, at cost, 14,500 shares (145,887) --
- ----------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 14,991,847 10,864,202
- ----------------------------------------------------------------------------------------------
$32,128,245 $25,224,724
===============================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-5
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF LOSS
- --------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Oil and gas revenues $ 6,656,758 $ 5,241,076 $ 3,017,252
Pipeline transportation revenues 296,331 -- --
Interest Income 43,597 45,905 19,094
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues and other income 6,996,686 5,286,981 3,036,346
- ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Production costs and taxes 2,951,746 2,614,414 2,564,932
Depreciation, depletion and amortization
(Notes 4 and 5) 1,849,963 371,249 233,807
General and administrative costs 2,957,871 2,602,311 1,961,348
Interest expense 850,965 415,376 417,497
Public relations 293,448 106,195 86,061
Professional fees (Note 11) 355,480 719,320 444,624
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and expenses 9,259,473 6,828,865 5,708,269
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS (2,262,787) (1,541,884) (2,671,923)
Dividends on preferred stock (391,183) (257,557) (119,347)
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS $(2,653,970) $(1,799,441) $(2,791,270)
- ------------------------------------------------------------------------------------------------------------------------------------
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS PER SHARE
Basic and diluted $ (0.26) $ (0.19) $ (0.33)
- ------------------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding 10,235,253 9,253,622 8,557,395
- ------------------------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-6
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
- --------------------------------------------------------------------------------
UNAMORTIZED
COMMON STOCK ADDITIONAL COMMON STOCK
--------------------------- PAID-IN ACCUMULATED STOCK OPTION
SHARES AMOUNT CAPITAL DEFICIT ISSUABLE AWARDS
- ------------------------------ -------------- ------------- -------------- ------------- -------------- -------------
BALANCE, January 1, 1999 7,644,212 $7,644 $16,796,038 $(10,496,092) $ 700,000 $(162,500)
Net loss -- -- -- (2,671,923) -- --
Common stock issued on
conversion of debt 83,100 83 508,917 -- -- --
Common stock issued for
exercised options 20,000 20 9,980 -- -- --
Stock option awards and
amortization, net -- -- -- -- -- 162,500
Common stock issued in
private placements, net
of related expense 775,802 776 3,471,722 -- (700,000) --
Stock issued for services 9,768 10 41,990 -- -- --
Dividends on convertible
redeemable preferred stock -- -- -- (119,347) -- --
Other -- -- (95,888) -- -- --
- ----------------------------- --------- ------ ----------- ----------- --------- ---------
BALANCE, December 31, 1999 8,532,882 8,533 20,732,759 (13,287,362) -- --
Net loss -- -- -- (1,541,884) -- --
Common stock issued on
conversion of debt 73,669 74 449,920 -- -- --
Common stock issued for
exercised options 20,715 21 179,992 -- -- --
Common stock issued on
conversion of preferred stock 8,818 9 49,991 -- -- --
Stock option awards for
professional services -- -- 242,000 -- -- --
Common stock issued in
private placements, net of
related expense 654,098 654 4,245,054 -- -- --
Stock issued for services 5,376 5 41,993 -- -- --
Dividends on convertible
redeemable preferred stock -- -- -- (257,557) -- --
- ----------------------------- --------- ------ ----------- ----------- --------- ---------
Balance, December 31, 2000 9,295,558 $9,296 $25,941,709 $(15,086,803) $ -- $ --
TREASURY STOCK
----------------------------
SHARES AMOUNT TOTAL
-------------- ------------- --------------
-- $ -- $ 6,845,090
(2,671,923)
-- -- 509,000
-- -- 10,000
-- -- 162,500
------------
-- -- 2,772,498
-- 42,000
-- -- (119,347)
-- -- (95,888)
---------- ------- ------------
-- -- 7,453,930
-- -- (1,541,884)
-- -- 449,994
-- -- 180,013
-- -- 50,000
-- -- 242,000
-- -- 4,245,708
-- -- 41,998
-- -- (257,557)
---------- ------- ------------
$ -- $ -- $ 10,864,202
F-7
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
- --------------------------------------------------------------------------------
UNAMORITIZED
COMMON STOCK ADDITIONAL COMMON STOCK
-------------------- PAID-IN ACCUMULATED STOCK OPTION
SHARES AMOUNT CAPITAL DEFICIT ISSUABLE AWARDS
=====================================================================================================================
BALANCE,
December 31, 2000,
brought forward 9,295,558 $9,296 $25,941,709 $(15,086,803) $ -- $ --
Net loss -- -- -- (2,262,787) -- --
Common stock issued
with 5% stock
dividend
(Note 10) 498,016 498 6,374,111 (6,374,609) -- --
Common stock issued
on conversion of debt 93,069 93 523,157 -- -- --
Common stock issued
for exercised options 274,932 275 2,340,725 -- -- --
Common stock issued
on conversion of
preferred stock 12,347 13 70,988 -- --
Stock option awards
for services 10,000 10 69,990 -- -- --
Common stock issued
in private placements,
of related expense 374,733 374 3,899,624 -- -- --
Common stock issued
as a charitable
donation 1,950 2 22,251 -- -- --
Treasury stock
purchased -- -- -- -- -- --
Dividends on
convertible
redeemable
preferred stock -- -- -- (391,183) -- --
=====================================================================================================================
BALANCE,
December 31, 2001 10,560,605 $10,561 $39,242,555 $(24,115,382) $ -- $ --
=====================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
TREASURY STOCK
------------------
SHARES AMOUNT TOTAL
=======================================
-- $ -- $ 10,864,202
-- -- (2,262,787)
-- -- --
-- -- 523,250
-- -- 2,341,000
-- -- 71,001
-- -- 70,000
-- -- 3,899,998
-- -- 22,253
14,500 (145,887) (145,887)
-- -- (391,183)
- --------- ------- ------------
14,500 $(145,887) $ 14,991,847
=======================================
F-8
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
YEARS ENDED DECEMBER 31, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss $(2,262,787) $(1,541,884) $(2,671,923)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depreciation, depletion and amortization 1,849,963 371,249 233,807
Compensation and services paid in stock options, stock
warrants, and common stock 92,253 284,000 204,500
Gain on sale of equipment (132,943) -- --
Changes in assets and liabilities:
Accounts receivable 3,814 (301,421) (386,933)
Inventory 91,981 8,408 (159,455)
Accounts payable - trade 191,702 364,553 300,342
Accrued interest payable (2,519) 135,435 --
Accrued liabilities (52,640) (140,955) (107,341)
- -----------------------------------------------------------------------------------------------------------------
Net cash used in operating activities (221,176) (820,615) (2,587,003)
- -----------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to other property and equipment (285,722) (1,276,783) (256,045)
Net additions to oil and gas properties (4,821,883) (1,456,996) (788,029)
Additions to pipeline facilities (4,213,095) (6,834,196) (193,633)
Decrease (increase) in restricted cash (120,872) 625,000 (625,000)
Other 32,888 6,112 (29,587)
- -----------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (9,408,684) (8,936,863) (1,892,294)
=================================================================================================================
F-9
YEARS ENDED DECEMBER 31, 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from exercise of options 2,341,000 180,013 10,000
Proceeds from borrowings 10,442,068 6,493,563 2,119,023
Repayments of borrowings (8,833,325) (1,720,856) (2,383,605)
Net proceeds from issuance of common stock 3,900,000 4,245,700 2,771,722
Proceeds from private placements of convertible
redeemable preferred stock, net 1,591,150 2,000,000 1,188,900
Collection of due from stockholder -- -- 400,000
Dividends on convertible redeemable preferred stock (357,503) (257,557) (119,347)
Purchase of treasury stock (145,887) -- --
Payment of loan fees (518,167) -- --
- -----------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 8,419,336 10,940,863 3,986,693
- -----------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,210,524) 1,183,385 (492,604)
CASH AND CASH EQUIVALENTS, beginning of year 1,603,975 420,590 913,194
- -----------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, end of year $ 393,451 $ 1,603,975 $ 420,590
- -----------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND
FINANCING ACTIVITIES:
During 2001, the Company issued a 5% $ $
stock dividend of 498,016 shares $ 6,374,609 -- --
During 2001 and 2000, the Company converted $
preferred stock to common stock $ 71,000 $ 50,000 --
During 2001, 2000 and 1999, respectively,
the Company issued common stock on
conversion of debt $ 523,250 $ 450,000 $ 509,000
During 2001, 2000 and 1999, respectively, the
Company issued common stock and stock options
for services received and charitable contributions
made $ 92,253 $ 284,000 $ 42,000
During 2001, the Company sold equipment $ $
for equity investments $ 150,000 -- --
=================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-10
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
1. SUMMARY OF ORGANIZATION
SIGNIFICANT ACCOUNTING Tengasco, Inc. (the "Company"), a publicly held
POLICIES corporation, was organized under the laws of the
State of Utah on April 18, 1916, as Gold Deposit
Mining and Milling Company. The Company
subsequently changed its name to Onasco Companies,
Inc.
Effective May 2, 1995, Industrial Resources
Corporation, a Kentucky corporation ("IRC"),
acquired voting control of the Company in exchange
for approximately 60% of the assets of IRC.
Accordingly, the assets acquired, which included
certain oil and gas leases, equipment, marketable
securities and vehicles, were recorded at IRC's
historical cost. The transaction was accomplished
through the Company's issuance of 4,000,000 shares
of its common stock and a $450,000, 8% promissory
note payable to IRC. The promissory note was
converted into 83,799 shares of Tengasco, Inc.
common stock in December 1995.
The Company changed its domicile from the State of
Utah to the State of Tennessee on May 5, 1995 and
its name was changed from "Onasco Companies, Inc."
to "Tengasco, Inc."
The Company's principal business consists of oil
and gas exploration, production and related
property management in the Appalachian region of
eastern Tennessee and in the state of Kansas. The
Company's corporate offices are in Knoxville,
Tennessee. The Company operates as one reportable
business segment, based on the similarity of
activities.
During 1996, the Company formed Tengasco Pipeline
Corporation ("TPC"), a wholly-owned subsidiary, to
manage the construction and operation of a 65-mile
gas pipeline as well as other pipelines planned
for the future. During 2001, TPC began
transmission of natural gas through its pipeline
to customers of Tengasco.
BASIS OF PRESENTATION
The consolidated financial statements include the
accounts of the Company, Tengasco Pipeline
Corporation and Tennessee Land and Mineral, Inc.
All significant intercompany balances and
transactions have been eliminated.
F-11
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
USE OF ESTIMATES
The accompanying financial statements are prepared
in conformity with accounting principles generally
accepted in the United States of America which
require management to make estimates and
assumptions that affect the reported amounts of
assets and liabilities and disclosure of
contingent assets and liabilities at the date of
the financial statements and the reported amounts
of revenues and expenses during the reporting
period. The actual results could differ from those
estimates.
REVENUE RECOGNITION
The Company recognizes revenues at the time of
exchange of goods and services.
CASH AND CASH EQUIVALENTS
The Company considers all investments with a
maturity of three months or less when purchased to
be cash equivalents.
RESTRICTED CASH
At December 31, 2001 the Company had cash in
escrow related to an ongoing pricing dispute with
King Pipeline Corporation. The Company is
disputing certain amounts billed by King Pipeline
Corporation to the Company for construction of the
pipeline. This cash will be restricted until a
judgment has been reached in this case.
INVESTMENT SECURITIES
Investment securities available for sale are
reported at fair value, with unrealized gains and
losses, when material, reported as a separate
component of stockholders' equity, net of the
related tax effect.
INVENTORY
Inventory consists primarily of crude oil in tanks
and is carried at market value.
F-12
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
OIL AND GAS PROPERTIES
The Company follows the full cost method of
accounting for oil and gas property acquisition,
exploration and development activities. Under this
method, all productive and nonproductive costs
incurred in connection with the acquisition of,
exploration for and development of oil and gas
reserves for each cost center are capitalized.
Capitalized costs include lease acquisitions,
geological and geophysical work, delay rentals and
the costs of drilling, completing and equipping
oil and gas wells. Gains or losses are recognized
only upon sales or dispositions of significant
amounts of oil and gas reserves representing an
entire cost center. Proceeds from all other sales
or dispositions are treated as reductions to
capitalized costs.
The capitalized costs of oil and gas properties,
plus estimated future development costs relating
to proved reserves and estimated costs of plugging
and abandonment, net of estimated salvage value,
are amortized on the unit-of-production method
based on total proved reserves. The costs of
unproved properties are excluded from amortization
until the properties are evaluated, subject to an
annual assessment of whether impairment has
occurred. The Company's proved gas reserves were
estimated by Columbia Engineering, independent
petroleum engineers, for the Kansas properties,
and by Coburn Petroleum Engineering for the
Tennessee properties in 1999. These reserves were
estimated by Ryder Scott Company, Petroleum
Consultants in 2000 and 2001.
The capitalized oil and gas property, less
accumulated depreciation, depletion and
amortization and related deferred income taxes, if
any, are generally limited to an amount (the
ceiling limitation) equal to the sum of: (a) the
present value of estimated future net revenues
computed by applying current prices in effect as
of the balance sheet date (with consideration of
price changes only to the extent provided by
contractual arrangements) to estimated future
production of proved oil and gas reserves, less
estimated future expenditures (based on current
costs) to be incurred in developing and producing
the reserves using a discount factor of 10% and
assuming continuation of existing economic
conditions; and (b) the cost of investments in
unevaluated properties excluded from the costs
being amortized. No ceiling writedown was recorded
in 2001, 2000 or 1999.
F-13
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
PIPELINE FACILITIES
Pipeline facilities under construction consist of
direct and indirect construction costs,
capitalized interest and capitalized overhead.
Phase I of the pipeline was completed during 1999.
Phase II of the pipeline was completed on March 8,
2001. Both phases of the pipeline were placed into
service upon completion of Phase II. The pipeline
is being depreciated over its estimated useful
life of 30 years, beginning at the time it was
placed in service. Accordingly, no depreciation
expense has been recorded for 2000 and 1999
relating to pipeline facilities. During 2001,
depreciation expense of $220,371 was recorded
relating to the pipeline.
OTHER PROPERTY AND EQUIPMENT
Other property and equipment are carried at cost.
The Company provides for depreciation of other
property and equipment using the straight-line
method over the estimated useful lives of the
assets which range from five to ten years.
IMPAIRMENT OF LONG-LIVED ASSETS AND LONG-LIVED
ASSETS TO BE DISPOSED OF
Management believes that carrying amounts of all
of the Company's long-lived assets will be fully
recovered over the course of the Company's normal
future operations. Accordingly, the accompanying
financial statements reflect no charges or
allowances for impairment.
DERIVATIVES
The Company uses collar contracts to partially
mitigate the effects of fluctuations in the price
of crude oil and natural gas. These contracts are
marked to market with current recognition of gains
and losses on such positions to be included in
Other Income since the Company's positions are not
considered hedges for financial reporting
purposes. The Company's accounting for collar
contracts may have the effect of increasing
earnings volatility in any particular period.
Derivative activities entered into on December 28,
2001 were not material to the Company's financial
position or results of operations as of and for
the year ended December 3,1 2001. The Company does
not hold or issue derivative instruments for
speculative purposes.
F-14
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
INCOME TAXES
The Company accounts for income taxes using the
"liability method." Accordingly, deferred tax
liabilities and assets are determined based on the
temporary differences between the financial
reporting and tax bases of assets and liabilities,
using enacted tax rates in effect for the year in
which the differences are expected to reverse.
Deferred tax assets arise primarily from net
operating loss carryforwards. Management evaluates
the likelihood of realization of such assets at
year end reserving any such amounts not likely to
be recovered in future periods.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject
the Company to concentrations of credit risk
consist principally of cash and accounts
receivable. At times, such cash in banks is in
excess of the FDIC insurance limit. At December
31, 2001, the Company had deposits with two
financial institutions in amounts which exceeded
the federally insured limit by approximately
$275,000 and $100,000.
The Company's primary business activities include
oil and gas sales to several customers in the
states of Tennessee and Kansas. The related trade
receivables subject the Company to a concentration
of credit risk within the oil and gas industry.
The Company has entered into a contract to supply
a chemical manufacturer with natural gas from the
Swan Creek field and through the pipeline. This
customer will be the Company's primary customer of
natural gas sales. Additionally, the Company sells
a majority of its crude oil primarily to two
customers, one each in Tennessee and Kansas.
Although management believes that customers could
be replaced in the ordinary course of business, if
the present customers were to discontinue business
with the Company, it could have a significant
adverse effect on the Company's projected results
of operations.
F-15
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
LOSS PER COMMON SHARE
Basic loss per share is computed by dividing loss
available to common shareholders by the weighted
average number of shares outstanding during each
year. Shares issued during the year are weighted
for the portion of the year that they were
outstanding. Diluted loss per share is not
calculated since it is anti-dilutive. Basic and
diluted loss per share are based upon 10,235,253
shares for the year ended December 31, 2001,
9,253,622 shares for the year ended December 31,
2000 and 8,557,395 shares for the year ended
December 31, 1999. There were 943,005, 1,000,763
and 732,967 potential weighted average common
shares outstanding during 2001, 2000 and 1999
related to common stock options and warrants.
These shares were not included in the computation
of the diluted loss per share amount because the
Company was in a net loss position and, thus, any
potential common shares were anti-dilutive. All
share and per share amounts have been adjusted to
reflect the 5% stock dividend. See Note 10.
FAIR VALUES OF FINANCIAL INSTRUMENTS
Fair values of cash and cash equivalents,
investments and short-term debt approximate cost
due to the short period of time to maturity. Fair
values of long-term debt are based on quoted
market prices or pricing models using current
market rates, which approximate carrying values.
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting
for Derivative Instruments and Hedging
Activities," effective January 1, 2001. SFAS No.
133 (as amended by SFAS 137 and SFAS 138) requires
a company to recognize all derivatives on the
balance sheet at fair value. Derivatives that are
not hedges must be adjusted to fair value through
income. If the derivative is a fair value hedge,
changes in the fair value of the hedged assets,
liabilities or firm commitments are recognized
through earnings. If the derivative is a cash flow
hedge the effective portion of changes in the fair
value of the derivative are recognized in other
comprehensive income until the hedged item is
recognized in earnings. The ineffective portion of
a derivative's change in fair value is immediately
recognized in earnings. The adoption of SFAS No.
133, as amended, did not have a material impact on
the Company's consolidated financial statements.
F-16
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In July 2001, the Financial Accounting Standards
Board issued Statement of Financial Accounting
Standard (SFAS) No. 141, "Business Combinations"
and SFAS No.142, "Goodwill and Other Intangible
Assets". SFAS No. 141 addresses the initial
recognition and measurement of goodwill and other
intangible assets acquired in a business
combination and SFAS No. 142 addresses the initial
recognition and measurement of intangible assets
acquired outside of a business combination whether
acquired individually or with a group of other
assets. These standards require all future
business combinations to be accounted for using
the purchase method of accounting. Goodwill will
no longer be amortized but instead will be subject
to impairment tests at least annually. The Company
would have been required to adopt SFAS No. 141 on
July 1, 2001, and to adopt SFAS 142 on a
prospective basis as of January 1, 2002. The
Company has not effected a business combination
and carries no goodwill on its balance sheet;
accordingly, the adoption of these standards is
not expected to have an effect on the Company's
financial position or results of operations.
In June 2001, the Financial Accounting Standards
Board approved the issuance of SFAS No. 143,
"Accounting for Asset Retirement Obligations."
SFAS 143 establishes accounting standards for the
recognition and measurement of legal obligations
associated with the retirement of tangible
long-lived assets and requires recognition of a
liability for an asset retirement obligation in
the period in which it is incurred. The provisions
of this statement are effective for financial
statements issued for fiscal years beginning after
June 15, 2002. The adoption of this statement is
not expected to have a material impact on the
Company's financial position or results of
operations.
SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, addresses
accounting and reporting for the impairment or
disposal of long-lived assets. SFAS No. 144
supersedes SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of. SFAS No. 144 establishes
a single accounting model for long-lived assets to
be disposed of by sale and expands on the guidance
provided by SFAS No. 121 with respect to cash flow
estimations. SFAS No. 144 becomes effective for
the Company's fiscal year beginning January 1,
2002. There will be no current impact of adoption
on its financial position or results of
operations.
F-17
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
RECLASSIFICATIONS
Certain prior year amounts have been reclassified
to conform with current year presentation.
2. GOING CONCERN The accompanying consolidated financial statements
UNCERTAINTY have been prepared in conformity with accounting
principles generally accepted in the United States
of America, which contemplate continuation of the
Company as a going concern which assumes
realization of assets and the satisfaction of
liabilities in the normal course of business. The
Company continues to be in the early stages of its
oil and gas related operating history as it
endeavors to expand its operations through the
continuation of its drilling program in the
Tennessee Swan Creek Field. Accordingly, the
Company has incurred continuous losses through
these operating stages and has an accumulated
deficit of $24,115,382 and a working capital
deficit of $6,326,204 as of December 31, 2001. On
April 5, 2002, the Company was informed by its
primary lender that $6,000,000 of its outstanding
credit facility was due and payable within 30
days, as provided for in the Credit Agreement (see
Note 7). These circumstances raise substantial
doubt about the Company's ability to continue as a
going concern.
The Company has disputed its obligation to make
this payment and is attempting to resolve the
dispute or to obtain alternative refinancing
arrangements to repay this current obligation.
There can be no assurance that the Company will be
successful in its plans to obtain the financing
necessary to satisfy their current obligations.
3. RELATED PARTY During 2001, the Company repaid all principal and
TRANSACTIONS interest due to related parties, using the
proceeds from the line of credit with Bank One.
Interest incurred to related parties was $546,026
for the year ended December 31, 2001.
During 2001, the Company converted debt of
$200,000 payable to a director into 42,017 shares
of common stock.
No consulting fees or commissions on equity
transactions were paid to related parties in 2001.
F-18
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
During 2000, the Company acquired debt financing
in the amount of $3,850,000 from two members of
the board of directors, one affiliate, and two
shareholders in order to complete construction of
its pipeline from Swan Creek to Kingsport (see
Note 5). The directors will also receive a
throughput fee once production begins, and will
continue to receive such fees until the debt is
repaid. The throughput fee is 10 cents per MMBtu
delivered through the pipeline in proportion to
the director's proportion of total debt. The
volume delivered shall be calculated on a monthly
basis. The throughput fee was $82,373 in 2001. No
throughput fees were incurred in 2000 or 1999 as
the pipeline was not yet operational.
During 2000, the Company incurred debt to a major
officer/stockholder in the amount of $995,000 in
order to purchase a drilling rig from that
officer/stockholder (see Note 7).
During 2000, the Company paid approximately
$270,000 in consulting fees and commissions on
equity transactions to a member of the Board of
Directors.
Interest expense incurred to related parties
during 2000 was $135,435.
In December 1999, the Company sold for aggregate
consideration of $625,000 a 25% working interest
in two wells and a 50% working interest in a third
well, located in the Swan Creek Field, to a
related party company affiliated with a member of
the Board of Directors.
During 1999, the Company converted $250,000 of
debt together with accrued interest thereon
payable to a major officer/stockholder of the
Company into 54,000 shares of common stock. In
addition, the Company converted $163,800 of
non-interest bearing accounts payable to this
officer/stockholder into 16,800 shares of common
stock.
During 1999, the Company converted $22,000 of debt
payable to a company owned by a member of the
Board of Directors for consulting services into
5,625 shares of common stock.
During 1999, the Company paid approximately
$218,000 in consulting fees and commissions on
equity transactions to a member of the Board of
Directors.
F-19
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
4. OIL AND GAS The following table sets forth information
PROPERTIES concerning the Company's oil and gas properties:
DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Oil and gas properties, at cost $15,117,224 $10,295,341
Accumulation depreciation,
depletion and amortization (1,847,294) (505,294)
-----------------------------------------------------------------------------
Oil and gas properties, net $13,269,930 $ 9,790,047
-----------------------------------------------------------------------------
During the years ended December 31, 2001, 2000 and
1999, the Company recorded depletion expense of
$1,342,000, $197,000 and $92,000, respectively.
Significant increases in depletion expense were
incurred during 2001 as a result of decreased oil
and gas estimated proved reserves.
5. PIPELINE FACILITIES In 1996, the Company began construction of a
65-mile gas pipeline (1) connecting the Swan Creek
development project to a gas purchaser and (2)
enabling the Company to develop gas distribution
business opportunities in the future. Phase I, a
30-mile portion of the pipeline, was completed in
1998. Phase II of the pipeline was completed in
March 2001. The estimated useful life of the
pipeline for depreciation purposes is 30 years.
The Company used the half-life convention to
calculate depreciation on the pipeline in 2001 and
recorded approximately $220,000 in depreciation
expense.
In January 1997, the Company entered into an
agreement with the Tennessee Valley Authority
("TVA") whereby the TVA allows the Company to bury
the pipeline within the TVA's transmission line
rights-of-way. In return for this right, the
Company paid $35,000 and agreed to annual payments
of approximately $6,200 for 20 years. This
agreement expires in 2017 at which time the
parties may renew the agreement for another 20
year term in consideration of similar
inflation-adjusted payment terms.
F-20
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
6. OTHER PROPERTY Other property and equipment consisted of the
AND EQUIPMENT following:
DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Machinery and equipment $1,737,189 $1,689,128
Vehicles 610,510 522,854
Other 63,739 63,734
-----------------------------------------------------------------------------
2,411,438 2,275,716
Less accumulated depreciation (731,334) (598,284)
-----------------------------------------------------------------------------
Other property and equipment - net $1,680,104 $1,677,432
-----------------------------------------------------------------------------
F-21
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
7. LONG TERM DEBT Long-term debt to unrelated entities consisted of
the following:
DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Revolving line of credit with a bank.
Initial borrowing base of $10,000,000.
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. The line of credit expires in
November 2004, unless extended by both
parities. Borrowings bear interest at
the bank's prime rate plus 0.25% (5% at
December 31, 2001). Collateralized by
the oil and gas properties and the
related operations and revenues. The
Company is subject to certain financial
(ratio) covenants and restrictions on
indebtedness, dividend payments,
financial guarantees, business
combinations, reporting requirements and
other related items. As of December 31,
2001, the Company is not in compliance
with all covenants, however, the bank
has waived its rights to accelerate the
debt or exercise other rights as a
result of these covenant violations.
Subsequent to year end, the bank reduced
the borrowing base to
$3,101,777. See Note 2. $9,101,777 $ --
Note payable to a bank, with $95,000
principal payments due monthly
commencing on January 1, 2001 through
February 1, 2003. Interest is
payable monthly commencing January 1,
2001 at prime plus 1% (5.75% at
December 31, 2001) per annum. The
note is guaranteed by a major
shareholder and is collatalized by
certain assets of the Company. The
note was repaid in 2001. -- 2,469,989
-----------------------------------------------------------------------------
Balance carried forward $9,101,777 $2,469,989
-----------------------------------------------------------------------------
F-22
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Balance brought forward $9,101,777 $2,469,989
-----------------------------------------------------------------------------
Note payable to an institution, with
$65,000 principal payments due quarterly
beginning January 1, 2000; remaining
balance due October 2003; with interest
payable monthly at 8% per annum. Note is
convertible into common stock of the
Company at a rate of $6.25 per share of
common stock.
Note is unsecured. 720,000 975,000
Note payable to an institution, with
$1,773.28 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/director and is
collateralized by certain assets of
the Company. 87,500 --
Thirteen individual vehicle and
equipment 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 2001 to 2006. 393,311 427,096
-----------------------------------------------------------------------------
Total long term debt due to unrelated
entities 10,302,588 3,872,085
Less current maturities (6,399,831) (1,608,486)
-----------------------------------------------------------------------------
Long term debt due to unrelated
entities, less current maturities $ 3,902,757 $ 2,263,599
-----------------------------------------------------------------------------
F-23
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Long-term debt to related parties
consisted of the following:
DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Note payable to a related party; entire
principal balance due December 2001,
with interest payable quarterly at 8%
per annum. Note is convertible into
common stock of the Company at a rate of
$5.00 per share of common
stock. $ -- $ 500,000
Note payable to a related party (Note
2); entire principal balance due
November 2005, with interest payable
quarterly at 8% per annum. Note is
convertible into common stock of the
Company at a rate of $7.10 per share
of common stock. Note is unsecured. -- 995,000
Note payable to related parties (Note
2); entire principal balance due
August 2005, with interest payable
quarterly at 10.75% per annum. Note
is collateralized by the Pipeline. -- 3,850,000
-----------------------------------------------------------------------------
Total long term debt due to related
parties -- 5,345,000
Less current maturities -- (500,000)
-----------------------------------------------------------------------------
Long term debt due to related parties,
less current maturities $ -- $ 4,845,000
-----------------------------------------------------------------------------
All long-term debt to related parties
was repaid in November 2001.
F-24
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The aggregate maturities of long term debt as of
December 31, 2001, are as follows:
Year Amount
-----------------------------------------------------------------------------
2002 $6,399,831
2003 390,793
2004 3,426,107
2005 59,200
2006 26,657
-----------------------------------------------------------------------------
$10,302,588
-----------------------------------------------------------------------------
8. COMMITMENTS The Company is a party to lawsuits in the ordinary
AND CONTINGENCIES course of its business. While the damages sought
in some of these actions are material, the Company
does not believe that it is probable that the
outcome of any individual action will have a
material adverse effect, or that it is likely that
adverse outcomes of individually insignificant
actions will be significant enough, in number or
magnitude, to have a material adverse effect in
the aggregate.
In the ordinary course of business the Company has
entered into various equipment and office leases
which have terms ranging from one to five years.
Approximate future minimum lease payments to be
made under noncancellable operating leases are as
follows:
Year Amount
-----------------------------------------------------------------------------
2002 $ 99,155
2003 60,158
2004 59,210
2005 56,970
2006 500
-----------------------------------------------------------------------------
$275,993
-----------------------------------------------------------------------------
Office rent expense was approximately $91,228,
$86,120 and $52,590 for each of the three years
ended December 31, 2001, respectively.
F-25
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
9. CONVERTIBLE In December 1998, the Company's Board of Directors
REDEEMABLE authorized the issuance of 100,000 shares of
PREFERRED STOCK Series A Convertible Redeemable Preferred Stock
("Series A Preferred Stock"). In December 1999,
the Company's Board of Directors authorized the
issuance of 100,000 shares of Series B Convertible
Redeemable Preferred Stock ("Series B Preferred
Stock").
Shares of both Series A and B of Preferred Stock
are or will be immediately convertible into shares
of Common Stock. Each $100 liquidation preference
share of preferred stock is convertible at a rate
of $7.00 for the Series A per share of common
stock. For the Series B, the conversion rate is
the average market price of the Company's common
stock for 30 days before the sale of the Series B
preferred stock with a minimum conversion price of
$9.00 per share. The conversion rate is subject to
downward adjustment if the Company subsequently
issues shares of common stock for consideration
less than $7.00 and $9.00 for the Series A and B,
respectively, per share. The conversion prices
will be adjusted prospectively for stock dividends
and splits.
In 2000, the Company issued 1,000 shares of Series
A Preferred Stock for $1,000,000, which netted the
Company approximately $960,000 after commissions.
In the same year, the Company issued 1,000 shares
of Series B Preferred Stock for $1,000,000. No
commissions were paid on the Series B Preferred
Stock. In April 2000, one holder converted 5,000
shares of Series A Preferred Stock into Common
Stock. No additional consideration was given to
the Company for this conversion.
In conjunction with the issuances of the Series B
Preferred Stock described above, the Company
granted the purchasers detachable stock warrants
which enable the holders to obtain up to 11,111
shares of the Company's common stock at an
exercise price of $9 per share.
In 2001, the Company issued 1,755 shares of Series
B Preferred Stock for $1,755,000, which netted the
Company approximately $1,591,000 after
commissions. In June 2001, one holder converted
710 shares of Series A Preferred Stock into Common
Stock. No additional consideration was given to
the Company for this conversion.
F-26
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The holders of both the Series A and Series B
Preferred Stock are entitled to a cumulative
dividend of 8% per quarter. However, the payment
of the dividends on the Series B Preferred Stock
is subordinate to that of the Series A Preferred
Stock. In the event that the Company does not make
any two of six consecutive quarterly dividend
payments, the holders of the Series A Preferred
Stock may appoint those directors which would
constitute of majority of the Board of Directors.
In such a scenario, the holders of the Preferred
Shares would be entitled to elect a majority of
the Board of Directors until all accrued and
unpaid dividends have been paid.
The Company may redeem both of the Series A and B
Preferred Shares upon payment of $100 per share
plus any accrued and unpaid dividends. Further,
with respect to the Series A Preferred Stock,
commencing on October 1, 2003 and at each
quarterly date thereafter while the Series A
Preferred Stock is outstanding, the Company is
required to redeem one-twentieth of the maximum
number of Series A Preferred Stock outstanding.
With respect to the Series B Preferred Stock, on
the fifth anniversary after issuance, the Company
is required to redeem all outstanding Series B
Preferred Stock.
10. STOCK DIVIDEND On August 1, 2001, the Company paid a 5% stock
dividend distributable on October 1, 2001 to
shareholders of record of the Company's common
stock on September 4, 2001. Based on the number of
common shares outstanding on the record date, the
Company issued 498,016 new shares. All references
in the accompanying financial statements to the
number of common shares and per share amounts are
based on the increased number of shares giving
retroactive effect to the stock dividend.
11. STOCK OPTIONS In October 2000, the Company approved a Stock
Incentive Plan. The Plan is effective for a
ten-year period commencing on October 25, 2000 and
ending on October 24, 2010. The aggregate number
of shares of Common Stock as to which options and
Stock Appreciation Rights may be granted to
Employees under the plan shall not exceed
1,000,000. Options are not transferable, are
exercisable for 3 months after voluntary
resignation from the Company and terminate
immediately upon involuntary termination from the
Company. The purchase price of shares subject to
this Nonqualified Stock Option Plan shall be
determined at the time the options are granted,
but are not permitted to be less than 85% of the
Fair Market Value of such shares on the date of
grant. Furthermore, an employee in the plan may
not, immediately prior
F-27
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
to the grant of an Incentive Stock Option
hereunder, own stock in the Company representing
more than ten percent of the total voting power of
all classes of stock of the Company unless the per
share option price specified by the Board for the
Incentive Stock Options granted such and Employee
is at least 110% of the Fair Market Value of the
Company's stock on the date of grant and such
option, by its terms, is not exercisable after the
expiration of 5 years from the date such stock
option is granted.
Stock option activity in 2001, 2000 and 1999 is
summarized below:
2001 2000 1999
------------------------- ------------------------ ------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
- -------------------------------------------------------------------------------------------------------------------
OUTSTANDING,
beginning
of year 1,017,450 8.54 530,250 $6.91 393,750 5.80
Granted 78,750 12.39 855,451 8.69 498,750 6.90
Exercised (256,772) 8.69 (21,751) 8.69 (21,000) 5.00
Expired/canceled (323,400) 7.85 (346,500) 6.91 (341,250) 5.66
---------- --------- --------
OUTSTANDING,
end of year 516,028 9.23 1,017,450 8.54 530,250 6.91
- --------------------------------------------------------------------------------------------------------------------
EXERCISABLE,
end of year 474,889 9.21 930,258 $8.49 246,687 5.50
- --------------------------------------------------------------------------------------------------------------------
The share information disclosed above has been
adjusted to reflect the 5% stock dividend declared
during 2001. See Note 10.
F-28
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The following table summarizes information about
stock options outstanding at December 31, 2001:
OPTIONS OPTIONS
OUTSTANDING EXERCISABLE
------------------------------------------ ----------------
WEIGHTED
WEIGHTED AVERAGE
AVERAGE REMAINING
EXERCISE CONTRACTUAL
PRICE SHARES LIFE (YEARS) SHARES
---------------------------------------------------------- ----------------
8.69 437,278 1.83 403,804
14.44 21,000 2.08 21,000
11.05 47,250 2.25 47,250
12.70 10,500 2.67 2,835
-------------- ----------------
Total 9.23 516,028 474,889
=============================================================================
The weighted average fair value of options granted
during 2001, 2000 and 1999 is $3.62, $3.41 and
$2.88 respectively, calculated using the
Black-Scholes Option-Pricing model.
The amount of compensation expense related to
stock options included in general and
administrative costs in the accompanying
consolidated statements of loss was approximately
$162,500 for the year ended December 31, 1999. No
compensation expense related to stock options was
incurred in 2001 or 2000. The Company issued
70,715 options to non-employees and non-directors
in 2000. The expense of $242,000 for these options
has been included in professional fees expense
because the options were issued to providers of
such services. The expense was calculated using a
fair market value of the options based on the
Black-Scholes option-pricing model assumptions
discussed below.
Statement of Financial Accounting Standards No.
123, ("SFAS 123"), "Accounting for Stock-Based
Compensation" was implemented in January 1996. As
permitted by SFAS 123, the Company has continued
to account for stock compensation to employees by
applying the provisions of Accounting Principles
Board Opinion No. 25. If the accounting provisions
of SFAS 123 had been adopted, net loss and loss
per share would have been as follows:
F-29
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
2001 2000 1999
-----------------------------------------------------------------------------------------------
Net loss available to common
shareholders
As reported $(2,653,970) $(1,799,441) $(2,791,270)
Pro forma (2,911,298) (4,052,452) (3,529,395)
-----------------------------------------------------------------------------------------------
Basic and diluted loss per share
As reported $ (0.26) $ (0.19) $ (0.33)
Pro forma (0.28) (0.44) (0.41)
-----------------------------------------------------------------------------------------------
For employees, the fair value of stock options
used to compute pro forma net loss and loss per
share disclosures is the estimated present value
at grant date using the Black-Scholes
option-pricing model with the following weighted
average assumptions for 2001, 2000 and 1999:
Expected volatility of 50% for 2001 and 2000 and
106% for 1999; a risk free interest rate of 3.67%
in 2001, 5.86% in 2000 and 6.17% in 1999; and an
expected option life of 3 years for 2001 and 2000
and 1.1 year in 1999.
12. INCOME TAXES The Company had no taxable income during the years
ended December 31, 2001, 2000 or 1999.
A reconciliation of the statutory U.S. Federal
income tax and the income tax provision included
in the accompanying consolidated statements of
loss is as follows:
YEAR ENDED DECEMBER 31, 2001 2000
-----------------------------------------------------------------------------
Statutory rate 34% 34%
Tax benefit at statutory rate $(769,000) $(452,500)
State income tax benefit (136,000) (75,500)
Nondeductible travel and
entertainment -- 19,000
Other -- 5,000
Increase in deferred tax asset
valuation allowance 905,000 504,000
-----------------------------------------------------------------------------
Total income tax provision $ -- $ --
-----------------------------------------------------------------------------
F-30
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The components of the net deferred tax assets are
as follows:
YEAR ENDED DECEMBER 31, 2001 2000
------------------------------------------------------------------------------
Net operating loss carryforward $ 5,877,000 $4,972,000
Capital loss carryforward 263,000 263,000
------------------------------------------------------------------------------
6,140,000 5,235,000
Valuation allowance (6,140,000) (5,235,000)
------------------------------------------------------------------------------
Net deferred taxes $ -- $ --
------------------------------------------------------------------------------
The Company recorded a valuation allowance at
December 31, 2001 and 2000 equal to the excess of
deferred tax assets over deferred tax liabilities
as management is unable to determine that these
tax benefits are more likely than not to be
realized.
As of December 31, 2001, the Company had net
operating loss carryforwards of approximately
$15,062,000, which will expire between 2010 and
2021, if not utilized.
Additionally, at December 31, 2001, the Company
had capital loss carryforwards of approximately
$81,000 which will expire, if not offset against
capital gains, in 2002.
13. SUPPLEMENTAL CASH The Company paid approximately $853,500, $544,000
FLOW INFORMATION and $479,000 for interest in 2001, 2000 and 1999,
respectively. The Company capitalized
approximately $148,000 and $128,000 of this amount
in 2001 and 2000, respectively. The Company paid
no income taxes in 2001, 2000 and 1999.
In 1999, the Company issued 54,000 shares of
common stock to convert a note payable to an
officer plus accrued interest thereon in the
approximate amount of $270,000, which approximated
the fair value of the shares.
In 2001, 2000 and 1999, the Company issued 11,950,
5,376 and 9,768 shares of common stock as
consideration for approximately $92,000, $42,000
and $42,000, respectively, of services and
charitable contributions which approximated the
fair value of the common stock.
F-31
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In 1999, the lender of the note payable with an
original balance of $1,500,000 sold $75,000 of
this note to other holders. These holders then
converted the notes into common stock at the rate
of $6.25 per share. In 2000, the lender converted
approximately $450,000 of the outstanding debt
into common stock under the same agreement.
14. QUARTERLY DATA AND The following table sets forth, for the fiscal
SHARE INFORMATION periods indicated, selected consolidated financial
(UNAUDITED) data and information regarding the market price
per share of the Company's common stock. The
prices represent the reported high and low closing
sale prices.
FISCAL YEAR ENDED 2001
-----------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
-----------------------------------------------------------------------------------
Revenues $ 1,448,318 $ 1,863,068 $ 2,583,758 $ 1,101,542
Net loss (368,768) (336,034) (378,597) (1,179,388)
Net loss available to common shareholders (447,546) (423,523) (491,055) (1,291,846)
- -----------------------------------------------------------------------------------------------------------------
Loss per common share
Basic and diluted $ (0.05) $ (0.04) $ (0.05) $ (0.12)
- -----------------------------------------------------------------------------------------------------------------
FISCAL YEAR ENDED 2000
- -----------------------------------------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------------------------------------------
Revenues $ 1,179,912 $ 1,270,283 $ 1,666,583 $ 1,124,298
Net Income (loss) (70,453) (379,234) 84,909 (1,177,106)
Net Income (loss) available to common
shareholders (110,231) (451,394) 18,064 (1,255,880)
- -----------------------------------------------------------------------------------------------------------------
Earnings (loss) per common share
Basic and diluted $ (0.01) $ (0.05) -- $ (0.13)
- -----------------------------------------------------------------------------------------------------------------
Third quarter 2001 results reflect the effect on
depletion expense that resulted from a decrease in
reserve estimates provided in a study performed by
Ryder Scott and issued August 10, 2001. The amount
recorded during this quarter was $562,000 higher
than the quarterly estimates made by management
during the first three quarters as a result of a
change in estimate arising from new information
provided in the Ryder Scott Report. Amounts
disclosed above differ from those filed with the
SEC during the third quarter of 2001 as a result
of an error in recording this change in estimate
to depletion at the time of
F-32
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
the filing. Management intends to amend the
September 30, 2001 SEC Form 10-Q filing.
15. SUPPLEMENTAL OIL AND Information with respect to the Company's oil and
GAS INFORMATION gas producing activities is presented in the
following tables. Estimates of reserve quantities,
as well as future production and discounted cash
flows before income taxes, were determined by
Ryder Scott Company, L.P. as of December 31, 2001
and 2000 and by Coburn Petroleum Engineering and
Columbia Engineering, independent petroleum
engineers, as of December 31, 1999.
OIL AND GAS RELATED COSTS
The following table sets forth information
concerning costs related to the Company's oil and
gas property acquisition, exploration and
development activities in the United States during
the years ended December 31, 2001, 2000 and 1999:
2001 2000 1999
========================================================================
Property acquisition
Proved $ -- $ -- $ 13,921
Unproved -- 5,702 17,265
Less - proceeds from
sales of properties (750,000) (1,176,411) (625,000)
Development costs 5,571,883 2,430,702 1,110,288
------------------------------------------------------------------------
$ 4,821,883 $ 1,259,993 $ 516,474
========================================================================
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, 2001 2000 1999
------------------------------------------------------------------------------
Revenues $ 6,656,758 $ 5,241,076 $ 3,017,252
Production costs and taxes (2,951,746) (2,614,414) (2,564,932)
Depreciation, depletion and
amortization (1,342,000) (197,000) (92,000)
------------------------------------------------------------------------------
Income from oil and gas
producing activities $ 2,363,012 $ 2,429,662 $ 360,320
==============================================================================
In the presentation above, no deduction has been
made for indirect
F-33
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
costs such as corporate overhead or interest
expense. No income taxes are reflected above due
to the Company's tax loss carryforwards.
OIL AND GAS RESERVES (UNAUDITED)
The following table sets forth the Company's net
proved oil and gas reserves at December 31, 2001
and 2000 and the changes in net proved oil and gas
reserves for the years then ended. Proved reserves
represent the estimated quantities of crude oil
and natural gas which geological and engineering
data demonstrate with reasonable certainty to be
recoverable in the future years from known
reservoirs under existing economic and operating
conditions. The reserve information indicated
below requires substantial judgment on the part of
the reserve engineers, resulting in estimates
which are not subject to precise determination.
Accordingly, it is expected that the estimates of
reserves will change as future production and
development information becomes available and that
revisions in these estimates could be significant.
Reserves are measured in barrels (bbls) in the
case of oil, and units of one thousand cubic feet
(MCF) in the case of gas.
F-34
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
OIL (BBLS) GAS (MCF)
-----------------------------------------------------------------------------
Proved reserves:
Balance, January 1, 1999 1,624,622 46,176,025
Discoveries and extensions 1,295,685 13,566,161
Revisions of previous estimates 444,893 15,268,361
Production (137,997) (215,260)
-----------------------------------------------------------------------------
Balance, December 31, 1999 3,227,203 74,795,287
Discoveries and extensions 56,103 1,059,147
Revisions of previous estimates (1,309,366) (27,998,986)
Production (159,035) (315,577)
-----------------------------------------------------------------------------
Balance, December 31, 2000 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)
-----------------------------------------------------------------------------
Proved reserves at, December 31, 2001 1,056,675 25,880,202
-----------------------------------------------------------------------------
Proved developed producing
reserves at, December 31, 2001 767,126 7,157,183
-----------------------------------------------------------------------------
Proved developed producing
reserves at, December 31, 2000 1,553,759 2,888,769
-----------------------------------------------------------------------------
Proved developed producing
reserves at, December 31, 1999 1,688,073 3,248,552
==============================================================================
Of the Company's total proved reserves as of
December 31, 2001 and 2000 and 1999, approximately
36%, 21% and 13%, respectively, were classified as
proved developed producing, 26%, 34% and 35%,
respectively, were classified as proved developed
non-producing and 37%, 45% and 52%, respectively,
were classified as proved undeveloped. All of the
Company's reserves are located in the continental
United States.
F-35
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS (UNAUDITED)
The standardized measure of discounted future net
cash flows from the Company's proved oil and gas
reserves is presented in the following table:
AMOUNTS IN THOUSANDS
December 31, 2001 2000 1999
-----------------------------------------------------------------------------
Future cash inflows $ 78,296 $ 505,733 $ 252,270
Future production
costs and taxes (26,083) (41,689) (30,598)
Future development costs (6,384) (8,225) (5,634)
Future income tax expenses -- (122,881) (55,090)
-----------------------------------------------------------------------------
Net future cash flows 45,829 332,938 160,948
Discount at 10% for
timing of cash flows (24,095) (97,195) (60,066)
-----------------------------------------------------------------------------
Discounted future net
cash flows from
proved reserves $ 21,734 $ 235,743 $ 100,882
==============================================================================
The following table sets forth the changes in the
standardized measure of discounted future net cash
flows from proved reserves during 2001 and 2000:
AMOUNTS IN THOUSANDS
2001 2000 1999
-------------------------------------------------------------------------------
BALANCE, beginning of year $ 235,743 $ 100,882 $ 42,976
Sales, net of production costs
and taxes (3,705) (2,627) (452)
Discoveries and extensions 4,167 1,778 27,394
Changes in prices and
production costs (299,527) 360,082 27,919
Revisions of quantity estimates (33,449) (186,289) 21,799
Development costs incurred -- 1,236 1,076
Interest factor - accretion
of discount 32,198 13,355 5,329
Net change in income taxes 86,237 (53,572) (22,869)
Changes in future development
costs 2,666 (3,237) 556
Changes in production rates
and other (2,596) 4,135 (2,846)
-------------------------------------------------------------------------------
BALANCE, end of year $ 21,734 $ 235,743 $ 100,882
==============================================================================
F-36
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Estimated future net cash flows represent an
estimate of future net revenues from the
production of proved reserves using current sales
prices, along with estimates of the operating
costs, production taxes and future development and
abandonment costs (less salvage value) necessary
to produce such reserves. The average prices used
at December 31, 2001, 2000 and 1999 were $17.03,
$25.62 and $23.01 per barrel of oil and $2.33,
$9.66 and $2.38 per MCF of gas, respectively. No
deduction has been made for depreciation,
depletion or any indirect costs such as general
corporate overhead or interest expense.
Operating costs and production taxes are estimated
based on current costs with respect to producing
gas properties. Future development costs are based
on the best estimate of such costs assuming
current economic and operating conditions.
Income tax expense is computed based on applying
the appropriate statutory tax rate to the excess
of future cash inflows less future production and
development costs over the current tax basis of
the properties involved, less applicable
carryforwards, for both regular and alternative
minimum tax.
The future net revenue information assumes no
escalation of costs or prices, except for gas
sales made under terms of contracts which include
fixed and determinable escalation. Future costs
and prices could significantly vary from current
amounts and, accordingly, revisions in the future
could be significant.
F-37