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, 2002 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 the aggregate market value of the voting stock held by non-affiliates
(based on the closing price on March 3, 2003 of $1.39): $8,378,799.
Indicate by checkmark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act): Yes / / No /X/
State the aggregate market value of the voting and non-voting common equity
held by non-affiliates computed by reference to the price at which the common
equity was last sold, or the average bid and asked price of such common equity,
as of the last business day of the registrant's most recently completed second
quarter (based on the closing price on June 28, 2002 of $2.80): $18,994,161.
State issuer's revenues for its most recent fiscal year: $5,700,478
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
3, 2003): 11,927,004
Documents Incorporated By Reference: None.
TABLE OF CONTENTS
Page
PART I
Item 1. Business.....................................................................................1
Item 2. Description Of Property.....................................................................22
Item 3. Legal Proceedings...........................................................................29
Item 4. Submission of Matters to a Vote of Security Holders.........................................32
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.......................33
Item 6. Selected Financial Data.....................................................................34
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operation...............................................................................35
Item 7A. Quantative and Qualitative Disclosures About Market Risk....................................46
Item 8. Financial Statements and Supplementary Data.................................................48
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure..............................................................................48
PART III
Item 10. Directors and Executive Officers of the Registrant...........................................49
Item 11. Executive Compensation.......................................................................55
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................58
Item 13. Certain Relationships and Related Transactions...............................................61
Item 14. Controls and Procedures.....................................................................63
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.............................64
SIGNATURES.......................................................................................................71
i
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 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 Hancock, Claiborne, Knox,
Jefferson and Union Counties in Tennessee. The Company's current lease position
in these areas in Tennessee is approximately 41,088 acres. See, "Item 2,
Description of Properties."
To date, the Company has been drilling primarily on a portion of its
Tennessee leases, known as the 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. The Company currently has 22 producing gas wells and 6
producing oil wells in the Swan Creek which produce approximately 1.4 MMcf of
natural gas per day and 2,200 barrels of oil per month. Revenues from the Swan
Creek Field were approximately $200,000 per month during 2002.
1
On March 8, 2001, the Company's wholly owned subsidiary, Tengasco Pipeline
Corporation ("TPC"), completed a 65 mile intrastate pipeline from the Swan Creek
Field to Kingsport, Tennessee at a cost of approximately $15.3 million. Until
the Company's pipeline was completed in 2001, the gas wells that had been
drilled in the Swan Creek Field could not be placed into actual production and
the gas transported and sold to the Company's industrial customers in Kingsport.
The Company initially believed that when actual production began from the Swan
Creek wells that the volumes of natural gas from the Swan Creek Field would be
significantly higher than the rates of actual production that have occurred
since production began. The reasons for the occurrence of lower production
volumes include initial production problems caused by naturally occurring fluids
entering the well bore, the slower than anticipated rate of production of the
wells due to underground reservoir characteristics that became apparent only
when the wells were placed into actual production, and the inability of the
Company to drill additional wells due to capital acquisition problems and
difficulties with the Company's primary lender, Bank One, N.A. of Houston, Texas
("Bank One"). The Company has taken steps to minimize fluid problems in existing
wells by mechanical means, and to prevent them in any future wells by drilling
and completion techniques. However, management believes that the only way to
increase production volumes of gas from this field is to drill additional wells
to most efficiently drain the underground reservoirs of the large reserves of
gas, and the Company's ability to do so is dependent upon raising the additional
capital for drilling. Although no assurances can be given, the current
management of the Company believes that it will be able to resolve the
difficulties currently preventing it from drilling additional wells and
increasing production volumes of natural gas from the Swan Creek Field.
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 were producing oil wells and 59 were producing gas wells, a related 50 mile
pipeline and gathering system, 3 compressors and 11 vehicles. The total purchase
price of these assets was approximately $5.5 million, which consisted of $3
million in cash and seller financing of $2.5 million. The seller financing
portion of the purchase price was refinanced by Arvest United Bank of Oklahoma
City, Oklahoma as evidenced by a note dated November 23, 1999 in the amount of
$1,883,650 to be paid in monthly installments of principal and interest over a
three year period. This obligation was subsequently satisfied from the proceeds
of a line of credit received by the Company from Bank One. See, "Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation."
The Kansas Properties are currently producing approximately 800,000 cubic
feet of natural gas and 336 barrels of oil per day. Net revenues from the Kansas
Properties were approximately $275,000 per month during 2002.
2
HISTORY OF THE COMPANY
The Company was initially organized under the laws of the State of Utah on
April 18, 1916, under the name "Gold Deposit Mining & Milling Company." The
Company subsequently changed its name to Onasco Companies, Inc. The Company was
formed for the purpose of mining, reducing and smelting mineral ores. On
November 10, 1972, the Company conveyed to an unaffiliated entity substantially
all of the Company's assets and the Company ceased all business operations. From
approximately 1983 to 1991, the operations of the Company were limited to
seeking out the acquisition of assets, property or businesses.
At a special meeting of stockholders held on April 28, 1995, the Company's
stockholders voted: (i) to approve the execution of an agreement (the "Purchase
Agreement") pursuant to which the Company would acquire certain oil and gas
leases, equipment, securities and vehicles owned by Industrial Resources
Corporation ("IRC")(1), a Kentucky corporation, in consideration of the issuance
of 4,000,000 post-split (as described below) "unregistered" and "restricted"
shares of the Company's common stock and a $450,000, 8% promissory note payable
to IRC. The promissory note was converted into 83,799 shares of the Company's
common stock in December 1995; (ii) to amend the Articles of Incorporation of
the Company to effect a reverse split of the Company's outstanding $0.001 par
value common stock on a basis of one share for two, retaining the par value at
$0.001 per share, with appropriate adjustments being made in the additional
paid-in capital and stated capital accounts of the Company; (iii) to change the
name of the Company from "Onasco Companies, Inc." to "Tengasco, Inc."; and, (iv)
to change the domicile of the Company from the State of Utah to the State of
Tennessee by merging the Company into Tengasco, Inc., a Tennessee corporation,
formed by the Company solely for this purpose.
The Purchase Agreement was duly executed by the Company and IRC, effective
May 2, 1995. The reverse split, name change and change of domicile became
effective on May 4, 1995, the date on which duly executed Articles of Merger
effecting these changes were filed with the Secretary of State of the State of
Tennessee; a certified copy of the Articles of Merger from the State of
Tennessee was filed with the Department of Commerce of the State of Utah on May
5, 1995. Unless otherwise noted, all subsequent computations herein
retroactively reflect this one for two reverse split.
During 1996, the Company formed TPC to manage the construction and
operation of its pipeline, as well as other pipelines planned for the future.
- ----------------------
(1) Malcolm E. Ratliff, the Company's former Chief Executive Officer, former
Chairman of the Board of Directors and former Director, is the the sole
shareholder of IRC.
3
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,
including the area now referred to as the Swan 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 apparent
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%.
A. SWAN CREEK PIPELINE FACILITIES
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.
In April 2000, TPC commenced construction of Phase II of the Company's
pipeline. This was an additional 35 miles of 8 and 12 inch pipe laid at a cost
of approximately $11.1 million extending the Company's pipeline from a point
near the terminus of Phase I and connecting to an existing pipeline and meter
station at Eastman Chemical Company's chemical plant. The pipeline system was
completed on March 8, 2001 at an overall cost of approximately $15.3 million and
extends 65 miles from the Company's Swan Creek Field to Kingsport, Tennessee.
4
B. SWAN CREEK CONTRACTUAL ARRANGEMENTS
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 had the option to install
facilities to treat the delivered gas so that the total non-hydrocarbon content
of the delivered gas is not greater than two percent (2%). This would have
allowed the gas to be used in certain processes in the Eastman plant requiring
low levels of non-hydrocarbons. If the Company elected to perform this option by
installing additional facilities, the minimum daily amount of gas to be
purchased by Eastman from the Company would increase to the lesser of (i)10,000
MMBtu's or (ii) eighty percent (80%) of the natural gas requirements of
Eastman's chemical plant.
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.
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 commenced upon the Company's completion of
construction of Phase II of its pipeline and connection to Eastman's facilities
and once commercial operation of that facility was approved which was in March
2001.
On January 25, 2000, TPC, 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 had no existing natural gas facilities and
the system to be installed by TPC was intended to initially extend to schools
and small customers, and gradually be expanded over time to
5
serve as many of the 6,900 residents of the County as is economically feasible.
TPC purchases gas from the Company on behalf of the District which is to be
resold at an average retail price of about $8.00 Mcf. Under the franchise
agreement, which has an initial term of ten years and may be renewed for an
additional ten years, TPC will receive 95% of the gross proceeds of the sale of
gas for its services under the agreement. In June, 2000, TPC began installation
of the necessary facilities to begin to serve 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. TPC 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, however, no gas sales agreements for large volume or base load sales
have been signed and there can be no assurances that such agreements will be
signed and if signed, it is not possible to predict when such sales may begin or
what the overall volumes of gas sold may be. Due to the small number of existing
customers and relatively high operating costs, the Company experienced a loss of
approximately $35,000 attributable to the operation of this system in 2002. The
Company intends to either expand the operation of this system so as to increase
revenues or to sell these assets to neighboring utilities or the City of
Sneedville. In the event of such a sale, the Company could still sell gas to the
Powell Valley Utility District.
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 may be between 1.8 million and 5 million cubic
feet, and volume could increase significantly over the life of the agreement as
BAE conducts additional operations at the Holston facility. The contract calls
for a price based on the monthly published index price for spot sales of gas at
the Henry Hub plus five cents per MMBtu in the same manner as the price is
calculated in the contract between the Company and Eastman.
The 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
6
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.
C. SWAN CREEK PRODUCTION AND DEVELOPMENT
The Company began delivering gas through its pipeline to BAE on April 4,
2001 and to Eastman on May 24, 2001. Daily production in June 2001 was 4,936.2
Mcf and in July 2001 daily production averages increased to 5,497 Mcf per day.
However, the Company was unable to maintain these production levels for the
remainder of 2001 and for 2002. This was due primarily to three factors: initial
fluid problems in some wells; natural and expected production declines from the
type of reservoir that exists in the Swan Creek field; and the inability of the
Company to offset expected natural declines in production by drilling new wells
because of funding difficulties caused in large part by the dispute with the
Company's primary lender Bank One. See, "Item 3 Legal Proceedings" and "Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation - Liquidity and Capital Resources" for a more detailed discussion of
the Bank One matter.
As to the first of these problems, the Company experienced the in-flow of
substantially more fluids in the existing wells than had been expected when they
were first brought into continuous production in 2001. These fluids entered the
wells from the boreholes. The fluids obstructed and significantly reduced the
flow of gas from the existing wells in the Swan Creek Field and required 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. Gas lifts have been installed in 15 of the
Company's existing wells and act as mechanisms to remove the fluids and
stabilize erratic behavior, such as large swings in individual well production.
These 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. The techniques used
in addressing these fluid problems will be applied in any future wells the
Company drills in the Swan Creek Field and it is anticipated that this will
minimize or prevent these problems.
Second, the Company experienced an expected and normal decline in initial
production from existing wells in a newly-producing field, such as Swan Creek,
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 Knox
formation in the Swan Creek Field to which the Company's existing wells have
been drilled and from which gas is currently being produced has both primary and
secondary porosity distributed throughout the
7
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.
Third, the declines in production have not been addressed and replaced by
additional drilling as the Company had expected. In order for overall field
production to remain steady or grow in a field such as the Swan Creek field, new
wells must be brought online. Any of the new wells drilled by the Company would
also experience the same harmonic (i.e. a relatively steep initial decline curve
followed by longer periods of relatively flat or stable production) decline as
does every natural gas well in a formation similar to the Knox formation, so
continuous drilling is vital to maintaining or increasing earlier levels of
production. Only two gas wells were added by the Company in 2002 due to the
destabilized lending arrangements caused by the actions of Bank One and ongoing
litigation regarding that matter. The Company anticipates that the natural
decline of production from existing wells is now predictable in Swan Creek, that
the total volume of the Company's reserves remains largely intact, and that
these reserves can be extracted through existing wells and also by steady
additional drilling brought on by reliable financial arrangements to fund
drilling. The Company is hopeful that it will be able to obtain additional or
replacement financing which will allow it to satisfy any indebtedness owed to
Bank One and to drill additional wells; however, no assurances can be made that
such financing will be obtained. See, "Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operation - Liquidity and Capital
Resources."
Due to natural and expected declines that continue to occur in ongoing
production from any oil and gas well, some additional declines are expected to
occur in production from the Company's existing wells in Swan Creek. The Company
expects these natural declines to be less than the decline experienced to date,
and that ongoing production from existing wells will tend to level off, in view
of two factors: first, additional work, repairs, and recompletions have been
performed on many of the existing wells; and second, the natural production
decline from any well is greatest during the initial producing periods, which
periods as to the Company's existing wells are now coming to the point where
future production is expected to remain relatively level. Declines in production
in the Swan Creek Field experienced in the last quarter of 2001 and the first
quarter of 2002 began to stabilize in March 2002 at approximately 2.5 million
cubic feet per day as these factors came into play. During the remainder of
2002, the Field continued to experience natural decline in production, although
the rate of the decline was slower as would normally be expected from a field
such as the Swan Creek Field.
Natural gas production from the Swan Creek field during 2002 averaged 2.567
million cubic feet per day in the first quarter; 2.553 million cubic feet per
day in the second quarter; 2.224 million cubic feet per day in the third
quarter; and, 1.467 million cubic
8
feet per day in the fourth quarter. This production history reflects a
combination of natural and expected decline from initial production from
existing wells, partially offset in the second and third quarters by the
addition of production from two new gas wells. During the fourth quarter, no
wells were added to offset the natural and expected declines in initial
production from existing wells.
The Company also experienced reductions or declines in its sales volumes
during certain times in 2002 for reasons unrelated to the production capability
of its wells or fields. These declines were caused by reductions in the
Company's customers' usage requirements or delivery restrictions. For example,
during the period from June 28, 2002 through July 29, 2002, Eastman temporarily
ceased its purchases from the Company because the Company was delivering most of
its then available volumes to supply BAE's newly increased requirements
resulting from BAE connecting additional gas burning facilities to its
operations. The Company was unable to sell all volumes of gas exceeding BAE's
increased requirements to Eastman, although the Company was able to produce
these volumes, because Eastman requires a minimum for its meters that available
volumes did not exceed, and a uniform rate of delivery that taking short term
volumes would interrupt. During the time Eastman was not purchasing gas from the
Company, BAE purchased additional volumes until BAE experienced a partial
equipment outage on July 15, 2002 and reduced its purchased volumes. As a result
of these occurrences, which were not within the control of the Company, the
Company's sales volume to BAE and Eastman in July 2002 declined to 42,382 Mcf or
an average of 1,367 Mcf per day. Eastman recommenced its purchases of gas from
the Company on July 29, 2002. Due to the combination of factors listed above
affecting the deliverability of gas from the Swan Creek Field, the Company
remains capable of delivering gas to both BAE and Eastman such deliverability
from the Swan Creek field of approximately 1.5 million cubic feet per day as of
March 31, 2003. In order to increase the volumes of gas for delivery from the
Swan Creek Field, the Company must drill additional wells. However, even if
additional wells are drilled, the Company anticipates based on all information
acquired to date that deliverability from the Swan Creek Field, once stabilized,
may not exceed approximately 3 million cubic feet per day.
During 2002, the Company deepened or drilled and completed three wells in
the Swan Creek field, the Colson No. 2, Paul Reed No. 8 and the Paul Reed No. 9,
to offset in part the normal and expected natural decline in production from the
Company's existing wells, and to thereby increase overall oil and gas production
capability and deliverability to BAE and Eastman.
In May, 2002, The Colson No. 2, previously an oil well with low production
levels, was deepened from approximately 3000 feet to 4,500 feet and successfully
recompleted as a gas well. The Colson No. 2 produced 59 million cubic feet of
gas in 2002 and is currently producing approximately 175,000 cubic feet per day.
On July 1, 2002, the Paul Reed No. 8 well was drilled to a total depth of
4,600 feet and although gas was present, based on information acquired during
drilling, the
9
Company determined that it was economically more beneficial to the Company in
view of current oil prices and the anticipated levels of potential gas
production, to complete this well as an oil well in the Murfreesboro and Stone
River formations at a depth of 2500-3200 feet. The Paul Reed No. 8 well was
successfully completed as an oil well and came in producing 100 barrels per day.
This well is currently producing approximately 65 barrels per day.
The Company drilled the Paul Reed No. 9 well to a total depth of 4,860 feet
and completed it as a gas well. The well was connected to the Company's pipeline
in early August 2002 and is currently producing approximately 200,000 cubic feet
of gas per day.
The completion stimulation techniques used on the Paul Reed No. 8 well were
also used on two existing oil wells with moderate success. The Paul Reed No. 5
which had stopped production in March 2002 due to paraffin build-up was
re-stimulated with a similar technique to enhance flow and limit build-up of
paraffin. Additional production was achieved, with 828 barrels produced in July
and 1,036 barrels in August 2002, and production continues to date. Altogether,
in September 2002, Swan Creek oil production achieved its highest monthly total
to date of 2,423 barrels, which increased again in October 2002 to 3,012 barrels
of oil. Despite these increases, oil production in the Swan Creek Field declined
from 30,323 barrels in 2001 to 20,122 barrels in 2002. This decline was due
primarily to the cessation of production from one of the Company's wells, the
Paul Reed No. 2 for mechanical reasons, although production from the Paul Reed
No. 8 largely offset the lost volumes from the Paul Reed No. 2. which has been
abandoned and will be plugged. The Company is presently reviewing key areas for
drilling of new oil wells in the Swan Creek Field. 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.
During 2002, the Company had 30 producing gas wells and seven 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 45 wells in the Swan Creek Field. 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. Of the completed
wells, twelve 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 Company has not been able to drill a substantial number of additional
gas or oil wells at Swan Creek in 2002 because it has not had sufficient funds
to do so. Although the Company had expected to commence and continue its
drilling program in 2002, the Company has been forced to postpone any further
drilling until additional funds become available and the dispute between the
Company and its primary lender
10
Bank One are resolved. Because the Knox formation has been defined by the
accumulation of data from previously drilled wells and seismic data, new
locations and new wells when drilled are expected to contribute significantly to
achieving increases to production totals. The Company believes that 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 has obtained approval from the Tennessee
regulatory authorities with jurisdiction over spacing of wells to drill
additional wells on smaller spacing units in the field, effectively allowing
more wells to be drilled and the reservoir to produce more quickly but with no
decrease in the long term efficiency of production of the maximum amount of
reserves from the reservoir. The Company is hopeful that production from these
new wells will be in line with its more productive existing wells in the Swan
Creek Field and will have a noticeable effect on increasing the total production
from the Field. 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 increase. However, even if such production increase does
occur, the deliverability from the Swan Creek Field will not be sufficient to
meet the Company's daily requirements under the contracts with BAE and Eastman.
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 50Mcf per day, the impact
of these targets is proportional both to an area and an extent that is yet
undefined. However, the Company can not proceed with such drilling until such
time that it has the funds to so.
D. RELATIONSHIP WITH THE UNIVERSITY OF TENNESSEE
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 who served as a Director of the Company in 2002, and Dr. Richard T.
Williams, Ph. D., Associate Professor in geophysics, who is currently the
Company's Chief Executive Officer and a Director of the Company, provide the
Company with assistance in interpreting the structure of the Swan
11
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. A number of UTK graduate 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 Agreement between the Company and the University of Tennessee also
provides for 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.
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 800 Mcf and 336 barrels of oil per
day. Revenue for the Kansas Properties was approximately $275,000 per month in
2002.
The Company employs a full time geologist in Kansas to oversee operations
of 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 has identified five new locations for drilling 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 did not drill any new wells in Kansas in 2002 due to lack
of funds available for such drilling. The Company is also engaged in gathering
for a fee the gas produced from wells owned by
12
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
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 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 was in Cocke County,
Tennessee which is approximately 40 miles southeast of the Swan Creek Field. In
2002, the Company, in conjunction with Southeast Gas & Oil Corp. of Newport,
Tennessee, drilled an approximately 6,000-foot exploratory well to the Knox
formation. This well did not result in any commercial quantities of
hydrocarbons.
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.
13
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.
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, the Company's former Chief Executive Officer and former Chairman of the
Board of Directors and a former Director of the Company. 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 Nami Resources,
14
LLC, Miller Petroleum, Inc., Knox Energy Development and Penn Virginia
Corporation. The Company is in a favorable position in the area in which its
pipeline is located. Within that area, the Company owns leases on approximately
41,088 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 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
15
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.
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.
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 TPC 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. TPC 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, TPC 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. The Company will not initiate the required
approval process for the ordinance and franchise agreement until such time that
it can supply gas to the City of Kingsport. 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
16
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.
TPC 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.
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
17
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 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 twenty-one 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:
18
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 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 has been reduced by Bank One,
although the Company vigorously disputes the Bank's actions. As a result of Bank
One's reduction of the credit facility and the corresponding demand for payment,
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 $27,776,726 and a working capital
deficit of $7,998,835 as of December 31, 2002, the Company's independent
certified public accountants have indicated in their report on the Company's
Consolidated Financial Statements for the year ended December 31, 2002, that
these circumstances contribute to uncertainty over the Company's ability to
continue as a going concern which depends upon its ability to obtain long-term
debt or raise capital to satisfy its cash flow requirements. 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. 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 and this would have an adverse impact on
the Company's ability to continue in business. Although management believes it
will be able to obtain the long-term debt or raise capital to enable it to
continue drilling and remain in business, there can be no assurances that it
will be able to obtain such funding. 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.
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 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
19
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 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.
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
20
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, 2002, 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 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 does not presently have any hedging agreements or plans
to enter into any hedging activities. However, to the extent that the Company
does enter into such agreements or undertake such activities, 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.
21
ITEM 2. DESCRIPTION OF PROPERTY
PROPERTY LOCATION, FACILITIES, SIZE AND NATURE OF OWNERSHIP
The Company's Swan Creek Leases are on approximately 41,088 acres in
Hancock, Claiborne, Knox, Jefferson, Morgan and Union Counties in Tennessee. The
initial terms of these leases vary from one to five years. Some of them will
terminate unless the Company has commenced drilling. However, the Company does
not anticipate any difficulty in continuing the Swan Creek Leases. In 2002, the
Company reduced the acreage comprising the Swan Creek Field from approximately
50,500 acres to the present 41,088 acres. This reduction in acreage was a result
of the Company having a better understanding of the geological and geophysical
makeup of the Swan Creek Field. Management believes the acreage eliminated from
the Field does not have the potential to produce commercial quantities of oil or
gas. The reduction of this acreage does not affect the reserves of the Swan
Creek Field or diminish its potential. Further, the elimination of the leases
for this acreage will result in beneficial cost savings to the Company.
Morita Properties, Inc., an affiliate of Shigemi Morita, a former Director
of the Company, currently has a 25% 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 all but two are presently producing wells. In addition, to those
interests, Morita Properties, Inc. previously owned a 25% working interest in
three of the Company's other existing wells and 12.5% working interest in
another of the Company's wells which it subsequently sold.
An individual who is not an affiliate of the Company purchased 25% working
interests in two other wells, the Stephen Lawson No. 1 and the Patton No. 1.
Both of these wells are located in the Swan Creek Field and are presently
producing wells.
Another individual has a 29% revenue interest in the Laura Jean Lawson No.
3 well by virtue of having contributed her unleased acreage to the drilling unit
and paying her proportionate share of the drilling costs of the well. The
Company was obligated to allow that individual to participate on that basis in
accordance with both customary industry practice and the requirements of the
procedures of the Tennessee Oil and Gas Board in a forced pooling action brought
by the Company to require the acreage to be included in the unit so that the
well could be drilled. The forced pooling procedure was concluded by her
contribution of acreage and agreement to pay 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 TPC will transport Miller's gas. The Company
reserved all offset locations to wells drilled under the farmout agreement. All
ten wells have been drilled under the farmout agreement. The Company acquired
back from Miller a 50% working interest from Miller in nine of those ten wells
in addition to its rights under the farmout agreement. In addition, the Company
and Miller have drilled two additional wells on
22
a 50-50 basis, although the Company declined to exercise its option for a
ten-well extension of the farmout agreement. Of the wells in which Miller owns
an interest, six are presently producing.
Other than the working interests described or referred to in this Item, the
Company retains all other working interests in wells drilled or to be drilled in
the Swan Creek Field.
Working interest owners in oil and gas wells are entitled to market their
respective shares of production to purchasers other than purchasers with whom
the Company has contracted. Absent such contractual arrangements being made by
the working interest owners, the Company is authorized but is not required to
provide a market for oil or gas attributable to working interest owners'
production. At this time, the Company has not agreed to market gas for any
working interest owner to customers other than customers of the Company. If the
Company does agree to market gas for working interest owners to the Company's
customers, the Company will have to agree, at that time, to the terms of such
marketing arrangements and it is possible that as a result of such arrangements,
the Company's revenues from such customers may be correspondingly reduced. If
the working interest owners make their own arrangements to market their natural
gas to other end users along the pipeline which have been served by East
Tennessee Natural Gas, an interstate pipeline, such gas would be transported
through the Company's wholly owned subsidiary TPC 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 and an office in Hays, Kansas at a rental of $500 per
month. During 2002 and the first quarter of 2003, the Company closed a field
office in Sneedville, Tennessee and an office in New York City it had previously
leased at an aggregate rental of $3,100 per month.
RESERVE ANALYSES
Ryder Scott Company, L.P. of Houston, Texas ("Ryder Scott") has performed
reserve analyses of all the Company's productive leases. Ryder Scott and its
employees and its registered petroleum engineers have no interest in the Company
or IRC, and performed these services at their standard rates. The net reserve
values used hereafter were obtained from a
23
reserve report dated February 10, 2003 (the "Report") prepared by Ryder Scott as
of December 31, 2002. In substance, the Report used estimates of oil and gas
reserves based upon standard petroleum engineering methods which include
production data, decline curve analysis, volumetric calculations, pressure
history, analogy, various correlations and technical judgment. Information for
this purpose was obtained from owners of interests in the areas involved, state
regulatory agencies, commercial services, outside operators and files of Ryder
Scott. The net reserve values in the Report were adjusted to take into account
the working interests that have been sold by the Company in various wells in the
Swan Creek Field. The Report provides that the net proved reserves for wells in
the Swan Creek Field are 30,360 MMcf of natural gas and 226,456 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, 2002 is $103,667,886 before
production taxes and $100,557,852 after production taxes. The Report further
provides that as of December 31, 2002 the value of the future net income before
income taxes of the Company's interest in the Swan Creek Field is $80,798,842
and, discounting the future net income by 10% results in a present value of
$36,230,728.
The Report reflects that the amount of proved natural gas reserves in the
Swan Creek Field of 30,360MMcf remained essentially unchanged from reserves of
30,366 MMcf reported in the Ryder Scott report dated March 28,2002 reporting
values as of December 31, 2001. The Report also reflects a decrease in the
amount of proved oil reserves to 224,456 barrels in 2002 from 319,650 barrels
reported in the earlier Ryder Scott report for values as of December 31, 2001.
This decrease was primarily due to estimates for the Colson #1 well which was
included in the earlier Ryder Scott report as of December 31, 2001, but was not
included in the current Report as that well was subsequently taken off-line and
reclassified as unproved. The Report reflects an increase from the Ryder Scott
Report for the year ended December 31, 2001 in the value of the future gross
revenues of the Company's interest in the Swan Creek Field from $57,832,005 to
$103,667,886 before production taxes and $56,097,044 after production taxes to
$100,557,852. The Report also indicates an increase in the discounted (at 10%
per annum compounded monthly) present value of the reserves of the Swan Creek
Field from $19,302,590 as of December 31, 2001 to $36,230,728 as of December 31,
2002. These increases in values reported by Ryder Scott in the Report are due to
an increase in oil and gas prices for 2002 making a larger portion of the
Field's undeveloped reserves more economical for future development. Gas prices
for the year-end 2001 Ryder Scott report utilized gas prices of $2.35 per Mcf
and oil prices of $16.25 per barrel as opposed to the $4.22 per Mcf price and
$26.90 per barrel price utilized in the current Report for the year ended
December 31, 2002. In addition, the Company drilled two wells in 2002, the
Colson #2 and the Paul Reed #9, which added 936 MMcf to the Company's gas
reserves in the Swan Creek Field.
Ryder Scott also performed a reserve analysis of the Kansas Properties. The
Report provides that as of December 31, 2002 the net proved reserves for the
Kansas Properties are 4,005 MMcf of natural gas and 1,586,258 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, 2002 is $48,511,771 before
production taxes and $48,066,045 after production taxes. The Report further
provides that as of December 31, 2002 the value of the future net income before
income taxes of the Company's interest in the Kansas Properties is $18,163,162
and, discounting the future net income by 10% results in a present value of
$10,417,292.
The current Report reflects a substantial increase from the Ryder Scott
Report
24
analyzing the reserves of the Kansas Properties as of December 31, 2001 in (i)
the number of barrels of oil attributed to the Company's net interest in the
Kansas Properties from 831,930 barrels to 1,308,467 and (ii) the value of the
future gross revenues of the Company's interest in the Kansas Properties from
$20,463,797 to $48,511,771 before production taxes and $19,586,607 after
production taxes to $48,066,045. The current Report also indicates an increase
in the discounted (at 10% per annum compounded monthly) net present value of the
Company's oil and gas reserves in the Kansas Properties from $2,431,317 as of
December 31, 2001 to $10,417,292 as of December 31, 2002. These increases are
due primarily to two factors. First, the increased price and future speculative
market for energy prices have driven both oil and gas prices higher. The 2001
Ryder Scott Report used a gas price of $2.13 per Mcf in determining the value of
reserves in contrast to the $4.13 per Mcf price used in the current Report and
an oil price of $17.24 per barrel in 2001 contrasted to the $27.29 per barrel
price used in 2002. Second, an increase in the number of barrels occurred
because the current Report for December 31, 2002 included the production and
reserves from approximately thirty producing oil wells that had not been
included in the prior Ryder Scott Report for December 31, 2001. At the time of
the earlier Report, the calculated operating expenses for those producing wells
matched or exceeded the oil price utilized in that Report and therefore, those
wells were not considered commercially viable for purposes of that earlier
Report. As a result of the increase in the price of oil, those wells and
associated reserves are included in the current Report. The Company anticipates
that future reports of the net present value of the Kansas Properties should
remain stable, and may even increase and will continue to include the
consideration of reserves attributable to all of the Company's wells in Kansas,
which are still producing in accordance with their extended production history,
provided that the market price of oil and gas remains constant or increases.
The Company believes that the reserve analysis reports prepared by Ryder
Scott for the Company for the Swan Creek Field and Kansas Properties provide an
essential basis for review and consideration of the Company's producing
properties by all potential industry partners and all financial institutions
across the country. It is standard in the industry for reserve analyses such as
these to be used as a basis for financing of drilling costs. Reserve analyses,
however, are at best speculative, especially when based upon limited production;
no assurance can be given that the reserves attributed to these leases exist or
will be economically recoverable. The result of any reserve analysis is
dependent upon the forecast of product prices utilized in the analysis which may
be more or less than the actual price received during the period in which
production occurs.
The Company has not filed the reserve analysis reports prepared by Ryder
Scott or any other reserve reports with any Federal authority or agency other
than the Securities and Exchange Commission. The Company, however, has filed the
information in the Report of the Company's reserves with the Energy Information
Service of the Department of Energy in compliance with that agency's statutory
function of surveying oil and gas reserves nationwide.
25
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 PRODUCTION COST OF AVERAGE SALES PRICE
ENDED PRODUCTION
DECEMBER (PER BOE)(2)
31
- --------------------------------------------------------------------------------------------------------------
OIL GAS OIL GAS
(BBL) (MCF) (BBL) (PER MCF)
- --------------------------------------------------------------------------------------------------------------
2002 15,111.54 521,834.35 $4.10(3) $21.85 $3.22
- --------------------------------------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------------------------------------
Gas volumes and prices for 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.
- ---------------------------
(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.
(3) The increase in cost of production in 2002 was a result of this being
the first full year of production in the Swan Creek Field.
26
KANSAS
- --------------------------------------------------------------------------------------------------------------
YEAR PRODUCTION COST OF AVERAGE SALES PRICE
ENDED PRODUCTION
DECEMBER (PER BOE)
31
- --------------------------------------------------------------------------------------------------------------
OIL GAS OIL GAS
(BBL) (MCF) (BBL) (PER MCF)
- --------------------------------------------------------------------------------------------------------------
2002 105,473.54 246,510.98 $ 8.71 $23.89 $2.96
- --------------------------------------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------------------------------------
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, 2000 and 2001 the Company did not drill any exploratory wells. In
2002, the Company drilled one exploratory well in Cocke County, Tennessee which
did not result in finding commercial quantities of hydrocarbons. The information
should not be considered indicative of future performance, nor should it be
assumed that there is necessarily any correlation between the number of wells
drilled, quantities of reserves found or economic value.
GROSS AND NET WELLS
The following tables set forth for the fiscal years ending December 31,
2000, 2001, and 2002 the number of gross and net development wells drilled by
the Company. The dry hole set forth in the table below is the Cocke County well
referred to above. The term gross wells means the total number of wells in which
the Company owns an interest, while the term net wells means the sum of the
fractional working interests the Company owns in gross wells.
27
- -------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31
2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
- -------------------------------------------------------------------------------------------------------------------
TENNESSEE
- -------------------------------------------------------------------------------------------------------------------
PRODUCTIVE WELLS 3 2.625 19 11.42 9 4.0515
- -------------------------------------------------------------------------------------------------------------------
DRY HOLES 1 .50 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
KANSAS
- -------------------------------------------------------------------------------------------------------------------
PRODUCTIVE WELLS 0 0 3 2.594 0 0
- -------------------------------------------------------------------------------------------------------------------
DRY HOLES 0 0 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
PRODUCTIVE WELLS
The following table sets information regarding the number of productive
wells in which the Company held a working interest as of December 31, 2002.
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 31 18.9 12 6.18
- -------------------------------------------------------------------------------------------------------------------
KANSAS 52 43.45 128 110.5
- -------------------------------------------------------------------------------------------------------------------
DEVELOPED AND UNDEVELOPED OIL AND GAS ACREAGE
As of December 31, 2002, 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.
28
- -------------------------------------------------------------------------------------------------------------------
DEVELOPED UNDEVELOPED
- -------------------------------------------------------------------------------------------------------------------
GROSS ACRES NET ACRES GROSS ACRES NET ACRES
- -------------------------------------------------------------------------------------------------------------------
TENNESSEE 1,840.00 1,065.38 41,088 35,952
- -------------------------------------------------------------------------------------------------------------------
KANSAS 9,666.00 8,080.44 22,711 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 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. On November 8, 2001, the Company signed a credit facility with Bank One,
N.A. in Houston, Texas whereby Bank One extended to the Company a revolving line
of credit of up to $35 million. The initial borrowing base under the facility
was $10 million.
On April 5, 2002, the Company received a notice from Bank One stating that
it had redetermined and reduced the then-existing borrowing base under the
Credit Agreement by $6,000,000 to $3,101,766. Bank One demanded that the Company
pay the $6,000,000 within thirty days. On May 2, 2002, the Company filed suit in
federal court in the Eastern District of Tennessee, Northeastern Division at
Greeneville to restrain Bank One from taking any steps pursuant to its Credit
Agreement to enforce its demand that the Company reduce its loan obligation or
else be deemed in default and for damages resulting from the wrongful demand.
TENGASCO, INC., TENGASCO LAND AND MINERAL CORPORATION AND TENGASCO PIPELINE
CORPORATION V. BANK ONE, NA, DOCKET NO. 2:02-CV-118. It is the position of the
Company that Bank One's demand that the Company reduce its loan from
$9,101,776.66 to $3,101,776.66 within thirty days, coming only four months after
the loan was made, in the absence of any change in the Company's production of
oil and gas from the time the loan was closed or the condition of the Company's
assets, without warning and prior to the receipt of a December 2002 reserve
report, without any basis or explanation, is a violation of the Credit Agreement
and an act of bad faith. The Company sought a jury trial and actual damages
sustained by it as a result of the wrongful demand, in the amount of $51,000,000
plus punitive damages in the amount of $100 million.
29
On July 1, 2002, Bank One filed its answer and counterclaim, alleging that
its actions were proper under the terms of the Credit Agreement, and in the
counterclaim, seeking to recover all amounts it alleges to be owed under the
Credit Agreement, including principal, accrued interest, expenses and attorney's
fees in the approximate amount of $9 million. No hearings have occurred or been
scheduled in the court proceeding. The Company has filed initial written
discovery requests from Bank One. On November 5, 2002, the Company and the Bank
reached preliminary agreement on terms of a potential settlement of the
litigation, subject to execution of formal settlement documents. The Company has
continued to pay the sum of $200,000 per month of principal due under the
original terms of the Credit Agreement, plus interest, and has reduced the
principal now outstanding to approximately $7.1 million. Although the parties
continue to attempt to reach settlement of all outstanding issues under the
preliminary agreement, the settlement has not been concluded. At a scheduling
conference held by the Court on February 21, 2003, a procedural schedule has
been set as requested by the Company leading toward a trial date of November 18,
2003 in the event settlement is not concluded.
2. On November 22, 2002, the Company and its then Chief Executive Officer,
Malcolm E. Ratliff, were served with complaint filed in the United States
District Court for the Eastern District of Tennessee, Knoxville, entitled PAUL
MILLER V. M. E. RATLIFF AND TENGASCO, INC., DOCKET NUMBER 3:02-CV-644. The
complaint seeks certification of a class action to recover on behalf of the
class of all persons who purchased shares of the Company's common stock between
August 1, 2001 and April 23, 2002, damages in an amount not specified which were
allegedly caused by violations of the federal securities laws, specifically Rule
10b-5 issued under the Securities Exchange Act of 1934 as to the Company and Mr.
Ratliff, and Section 20(a) the Securities Exchange Act of 1934 as to Mr.
Ratliff. The complaint alleges that documents and statements made to the
investing public by the Company and Mr. Ratliff misrepresented material facts
regarding the business and finances of the Company. The Company's initial review
of the allegations of the complaint against the Company discloses that the
allegations do not appear to be well founded and are without merit. The Company
intends to vigorously defend against all allegations of the complaint. The
Company has filed a motion to dismiss the action based on the failure of the
complaint to meet the requirements of the Securities Litigation Reform Act of
1995. If that motion is not granted, the Company will file its responsive
pleading and will contest the class certification issues and the substantive
allegations of the complaint.
3. The Company and its 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
Court 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 charges billed to TPC for engineering services in
connection with the planning and construction of Phase II of the Company's
pipeline, which runs from Rogersville to Kingsport, TN to serve Eastman Chemical
Company and Holston Ordnance. 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"), a division of Fenstermaker. The
counterclaim seeks damages for breach of contract and breach of
30
professional engineering standards caused by Caddum, including unauthorized
deviations from the pipeline route, which caused the Company to incur
significant additional costs. These costs included 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 District
Court rescheduled the case for a non-jury trial on May 8, 2003. On February 27,
2003, the parties reached an agreement in principle for the settlement of this
action, and settlement documents are being prepared for review by both parties.
In general, the proposed settlement framework contemplates a reduction in the
amount owed by the Company from that claimed in the complaint, and favorable
extended payment terms.
4. TENGASCO PIPELINE CORPORATION V. JAMES E. LARKIN AND KATHLEEN A.
O'CONNOR, No. 4929J in the Circuit Court for Hawkins County, Tennessee. This is
a condemnation proceeding brought by Tengasco Pipeline Corporation to acquire a
temporary construction easement and permanent right of way to maintain and
operate a portion of Phase I of the Company's pipeline in Hawkins County,
Tennessee. The court granted an order of possession to the Company in January,
1998 and the pipeline has been constructed across approximately 3,000 feet of
the property concerned in a rural and very steep locale. The Company has had the
right of way appraised at $4,000. The landowners, Mr. Larkin and Kathleen A. O
Connor who both live on the property, contest the appraised value of the
property and claim incidental damages to certain fish ponds located on their
property. The landowners, despite a lack of evidence of any fish raising or
aquaculture business actually being or having been operated on the premises or
of any actual losses to such business, have counterclaimed for $867,585 in
compensatory damages and $2.6 million in punitive damages arising from trespass
and other legal theories. The Court required the parties to attempt to mediate
this dispute and the mediation occurred in December, 2000. The parties were
unable to reach a mediated settlement and the matter has most recently been
scheduled for trial on January 29, 2003. The January 29, 2003 trial date has
been continued by the Court to an unspecified future date. The Court has ordered
the parties to a second mediation session which will occur in March or April,
2003. If settlement is not reached at mediation, the Company intends to
vigorously defend the allegations of the counterclaim because trial preparations
have not disclosed any fact that reasonably suggests a substantial adverse
result in this matter and the allegations of the counterclaim appear to be
without any credible basis.
5. The Company, its former Chief Executive Officer and former Director of
the Company, Malcolm E. Ratliff, and one of the Company's attorneys, Morton S.
Robson, were 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
31
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None during the fourth quarter of 2002.
32
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, 2001 and December 31, 2002
are set forth below. The prices for the first three quarters of 2001 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, 2002 8.19 5.80
June 30, 2002 6.49 2.71
September 30, 2002 3.45 2.20
December 31, 2002 2.90 1.05
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
33
HOLDERS
As of March 3, 2003 the number of shareholders of record of the Company's
common stock was 205 and management believes that there are approximately 2,387
beneficial owners of the Company's common stock.
DIVIDENDS
The Company under its credit agreement with Bank One is presently
restricted from paying dividends without Bank One's consent. The Company did not
pay any dividends with respect to the Company's common stock in 2002 and has no
present plans to declare any further dividends with respect to its common stock.
RECENT SALES OF UNREGISTERED SECURITIES
Except as previously reported in Quarterly Reports on Form 10-Q filed by
the Company, no other equity securities that were not registered under the
Securities Act of 1933, as amended, were sold or issued by the Company during
2002.
Management believes that all of the persons who were sold or issued common
stock or preferred stock during 2002 that was not registered under the
Securities Act of 1933, as amended, were either "accredited investors" as that
term is defined under applicable federal and state securities laws, rules and
regulations, or were persons who by virtue of background, education and
experience who could accurately evaluate the risks and merits attendant to an
investment in the securities of the Company. Further, all such persons were
provided with access to all material information regarding the Company, prior to
the offer or sale of these securities, and each had an opportunity to ask of and
receive answers from directors, executive officers, attorneys and accountants
for the Company. The offers and sales of such securities during 2002 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(4),
- --------------------------
(4) 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
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT DATA:
- ---------------------------------------------------------------------------------------------------------------------
Oil and Gas Revenues $5,437,723 $6,656,758 $5,241,076 $3,017,252 $2,078,101
- ---------------------------------------------------------------------------------------------------------------------
Production Costs and Taxes $3,094,731 $2,951,746 $2,614,414 $2,564,932 $1,943,944
- ---------------------------------------------------------------------------------------------------------------------
General and Administrative $1,868,141 $2,957,871 $2,602,311 $1,961,348 $1,372,132
- ---------------------------------------------------------------------------------------------------------------------
Interest Expense $578,039 $850,965 $415,376 $417,497 $574,906
- ---------------------------------------------------------------------------------------------------------------------
Net Loss $(3,154,555) $(2,262,787) $(1,541,884) $(2,671,923) $(3,083,638)
- ---------------------------------------------------------------------------------------------------------------------
Net Loss Attributable to
Common Stockholders $(3,661,334) $(2,653,970) $(1,799,441) $(2,791,270) $(3,083,638)
- ---------------------------------------------------------------------------------------------------------------------
Net Loss Attributable to $(0.33) $(0.26) $(0.19) $(0.33) $(0.42)
Common Stockholders Per
Share
- ---------------------------------------------------------------------------------------------------------------------
As of December 31(5 6),
2002 2001 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA:
- ---------------------------------------------------------------------------------------------------------------------
Working Capital Deficit $(7,998,835) $(6,326,204) $(708,317) $(1,406,263) $(1,929,215)
- ---------------------------------------------------------------------------------------------------------------------
Oil and Gas Properties, Net $13,864,321 $13,269,930 $9,790,047 $8,444,036 $7,747,655
- ---------------------------------------------------------------------------------------------------------------------
Pipeline Facilities, Net $15,372,843 $15,039,762 $11,047,038 $4,212,842 $4,019,209
- ---------------------------------------------------------------------------------------------------------------------
Total Assets $32,584,391 $32,128,245 $25,224,724 $15,182,712 $13,525,777
- ---------------------------------------------------------------------------------------------------------------------
Long-Term Debt $2,006,209 $3,902,757 $7,108,599 $3,119,293 $3,190,930
- ---------------------------------------------------------------------------------------------------------------------
Redeemable Preferred Stock $6,762,218 $5,459,050 $3,938,900 $1,988,900 $800,000
- ---------------------------------------------------------------------------------------------------------------------
Stockholders Equity $14,210,623 $14,991,847 $10,864,202 $7,453,930 $7,245,090
- ---------------------------------------------------------------------------------------------------------------------
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 $3,661,344
($0.33 per share) in 2002 compared to a net loss of $2,653,970 ($0.26 per share)
in 2001 and $1,799,441 ($0.19 per share) of common stock in 2000.
- --------------------------
(5) With respect to the pipeline facilities, during the years ended December 31,
2000, 1999, and 1998, this included portions which were under construction.
(6) No cash dividends have been declared or paid by the Company for the periods
presented.
35
The Company realized oil and gas revenues of $5,437,723 in 2002 as compared
to $6,656,758 in 2001 and $5,241,076 in 2000. The decrease in revenues in 2002
from 2001 was due to a decrease in volumes produced in 2002 from the volumes
produced in 2001. Gas produced from the Swan Creek Field was 717,701 MCF in 2002
as compared to 966,967 MCF in 2001, resulting in approximately $800,000 in
reduced revenues. Oil production from the Swan Creek Field was 20,122 barrels in
2002, down from 30,323 barrels in 2001, resulting in approximately $200,000 in
reduced revenues. Gas production from the Kansas Properties was 287,198 MCF in
2002 compared to 324,915 MCF in 2001, resulting in approximately $100,000 in
reduced revenues. Oil production from the Kansas Properties was 137,851 barrels
in 2002 compared to 147,029 barrels in 2001, resulting in approximately $200,000
in reduced revenues. The reason for the decrease in volumes produced in 2002 was
the Company's dispute with Bank One which significantly limited the Company's
ability to drill new wells and to work over under producing wells in Kansas. The
increased revenues in 2001 of $6,656,758 compared to $5,241,076 in 2000 was
primarily due to gas sales from the Swan Creek field of $2,563,935 being made
for the first time during 2001. However, oil sales decreased by approximately
$951,000 in 2001 from 2000 levels due to price decreases, as the number of
barrels produced remained constant.
The Company's subsidiary, TPC, had pipeline transportation revenues of
$259,677 in 2002, a decrease compared to of $296,331 in 2001, the first year of
transportation revenues.
The Company's production costs and taxes have increased each year from 2000
to 2002 as additional costs have been incurred to maintain the Kansas Properties
and to begin production from the Swan Creek Field in 2001 and to maintain it in
2002. The production costs and taxes increased from $2,951,746 in 2001 to
$3,094,731 in 2002. An increase in 2001 of $337,332 in production costs and
taxes as compared to 2000 was due primarily to the commencement of production
from the Swan Creek Field.
Depletion, depreciation, and amortization increased significantly in 2002
to $2,413,597 over 2001 and 2000 levels of $1,849,963 and $371,249,
respectively. The primary reason for the increase from 2002 over 2001 was due to
depreciation being taken for the first time for a full year on the Company's
pipeline facilities in 2002, whereas only a half year of depreciation was taken
in 2001 after the pipeline was placed in service in mid-year. Also,
approximately $186,000 of loan fees were amortized in 2002. The primary increase
in 2001 from 2000 was 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, in 2001 the Company took depreciation on the pipeline
for the first time ($220,371).
The Company has significantly reduced its general administrative costs to
$1,868,141 in 2002 from $2,957,871 in 2001. Management has made a significant
36
effort to control costs in every aspect of its operations. Some of these cost
reductions include the closing of the New York office and a reduction in
personnel from 2001 levels. General and administrative expenses had increased to
$2,957,871 in 2001 from $2,602,311 in 2000. The increases in 2001 from 2000 were
attributable to an increase in insurance of approximately $400,000 in 2001 to
expand coverage including blowout insurance and the addition of Company provided
medical insurance for employees.
Interest expense for 2002 decreased significantly over 2001 levels due to
the reduced interest rate on the Bank One loan over the rate applicable under
previous financing arrangements. Interest expense in 2002 was $578,039 compared
to $850,965 in 2001. Interest expense for 2001 had in turn increased
significantly from $415,376 in 2000. This increase was due to additional
interest cost associated with financing for the completion of Phase II of the
Company's 65 mile pipeline. The increase in 2001 was reduced by interest cost of
approximately $148,000 which was capitalized in the first 3 months of 2001
during construction of the pipeline. Interest of $128,000 was capitalized in
2000.
Public relations costs were significantly reduced in 2002 to $193,229 from
$293,448 in 2001 as the Company applied cost saving methods in the preparation
of the Annual Report and in publishing of press releases. Public relations costs
increased to $293,448 in 2001 as compared to 2000 costs of $106,195 due to costs
associated with producing the annual report, the proxy statement, and press
releases.
Professional fees increased to $707,296 in 2002 from $355,480 in 2001 due
to legal and accounting services primarily related to the Bank One litigation
and new accounting regulations. Professional fees had decreased substantially in
2001 from 2000 fees of $719,320 which included a charge in 2000 of $242,000 for
stock options issued in 2000 to non-employees.
Dividends on preferred stock increased to $506,789 in 2002 from $391,183 in
2001 and from $257,557, in 2000 as a result in the increase in the amount of
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 initial borrowing base under the Credit
Agreement was $10 million. 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); (2) payoff 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); (3) payoff a
37
note due to Spoonbill, Inc. for funds borrowed by the Company for working
capital ($1,080,833); (4) payoff 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); and, (5) payoff 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). 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.
On or about April 5, 2002, the Company received a notice from Bank One
stating that it had redetermined and reduced the borrowing base under the Credit
Agreement to $3,101,776.66 and the Bank required a $6 million reduction of the
outstanding loan.
The schedule of reserve reports required by the Credit Agreement upon which
such redeterminations were to be based specifically established a procedure
involving an automatic monthly principal payment of $200,000 commencing February
1, 2002. The Company has remained current in payments of this monthly principal
reduction through March 1, 2003. As of the date of this Report, the outstanding
principal balance under the Credit Agreement was $6,901,776.66.
As a result of Bank One's unexpected reduction of the borrowing base and
the corresponding demand for payment of $6 million, combined with the fact that
the Company is still in the early stages of its oil and gas operating history
during which time it has had a history of losses from operations and has an
accumulated deficit of $27,776,726 and a working capital deficit of $7,998,835
as of December 31, 2002, the Company's independent auditors indicated in their
report on the audit of the Company's consolidated financial statements for the
year ended December 31, 2002 that the Company's ability to continue as a going
concern is uncertain. The Company's ability to continue as a going concern
depends upon its ability to obtain long-term debt or raise capital and satisfy
its cash flow requirements.
On May 2, 2002, the Company filed suit against Bank One in Federal Court in
the Eastern District of Tennessee, Northeastern Division at Greeneville,
Tennessee to restrain Bank One from taking any steps pursuant to its Credit
Agreement with the Company to enforce its demand that the Company reduce its
loan obligation or else be deemed in default and for actual and punitive damages
resulting from the wrongful demand in the amount of $150 million.
On July 1, 2002, Bank One filed its answer and counterclaim, alleging that
its actions were proper under the terms of the Credit Agreement, and in the
counterclaim, seeking to recover all amounts it alleges to be owed under the
Credit
38
Agreement, including principal, accrued interest, expenses and attorney's fees
in the approximate amount of $9 million.
On November 5, 2002, the Company and Bank One concluded a series of
meetings and correspondence by reaching preliminary agreement upon the basic
terms of a potential settlement. Any settlement is conditioned upon execution of
final settlement documents, and the parties agreed to attempt to close the
settlement by November 29, 2002. The principal element of the settlement
proposal is for the Bank and the Company to enter into an amended and restated
agreement for a new term loan to replace the prior revolving credit facility.
The proposed settlement agreement would place specific limits and requirement
upon any ability of Bank One to require a reduction of the loan balance. Such a
reduction could only occur in the event the value of the oil and gas reserves of
the Company falls below an agreed-upon figure in relation to the loan balance,
pursuant to a formula which management is satisfied provides ample protection
against any future reasonable likelihood of a similar problem arising in the
manner causing initiation of the litigation between the Company and Bank One. As
of the date of this report, the Company and Bank One continue to negotiate the
terms of a mutually satisfactory settlement agreement.
Even if the Company concludes a settlement with Bank One, the Company does
not anticipate that it will be able to either increase its borrowing base under
the Bank One Credit Agreement or to borrow any additional sums from Bank One. To
fund additional drilling and to provide additional working capital, the Company
would be required to pursue other options. 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 activities.
The harmful effects upon operations of the Company caused by the actions of
Bank One and the ongoing litigation with Bank One in 2002 have been dramatic.
First, the action of Bank One in April, 2002 (less than five months after it had
entered into the credit facility agreement with the Company and received
substantial fees for the providing the credit facility) of reducing the
Company's credit line to a point $6 million below its then-existing indebtedness
and then calling for payment of that $6 million within thirty days had the
effect of totally cutting off any additional funds to the Company to support
Company operations. Further, the funds loaned to the Company by Bank One had
been used to refinance the Company's indebtedness and no funds were then
available to pay this large repayment obligation to Bank One, even if such
action by the Bank was proper, which the Company has vigorously and continually
denied. The principal reason the Company had entered into the Bank One credit
agreement was to provide for additional funds to promote the growth of the
Company. Consequently, as a result of Bank One's unwarranted actions no
additional funds under the credit facility agreement were available in 2002 for
additional drilling that the Company had anticipated performing in the Swan
Creek Field and which were critical to the
39
development of that Field. In order for overall field production to remain
steady or grow in a field such as the Swan Creek Field, new wells must be
brought online. Any of the new wells drilled by the Company would also
experience a relatively steep initial decline curve followed by longer periods
of relatively flat or stable production decline, as does every natural gas well
in a formation similar to the Knox formation, so continuous drilling is vital to
maintaining or increasing earlier levels of production. Only two gas wells were
added by the Company in 2002 due to the destabilized lending arrangements caused
by the actions of Bank One and ongoing litigation.
Second, the existence of the dispute with Bank One, compounded by the fact
that an effect of Bank One's action was to cause the Company's auditors to
indicate that their was an uncertainty over the Company's ability to continue as
a going concern, has significantly discouraged other institutional lenders from
considering a variety of additional or replacement financing options for
drilling and other purposes that may have ordinarily been available to the
Company. Third, the dispute has caused Bank One to fail to grant permission
under the existing loan agreements with the Company to permit the Company to
formulate drilling programs involving potential third party investors that may
have permitted additional drilling to occur. Finally, the dispute has caused the
Company to incur significant legal fees to protect the Company's rights.
The Company believes that the total volume of the Company's reserves in the
Swan Creek Field remains largely intact, and that these reserves can be
extracted through existing wells and by steady additional drilling brought on by
reliable financial arrangements. The Company plans to drill as many as twenty
additional wells in the heart of this Field and has obtained approval from the
Tennessee regulatory authorities with jurisdiction over spacing of wells to
drill on smaller spacing units in the Field, effectively allowing more wells to
be drilled and the reservoir to produce more quickly but with no decrease in the
long term efficiency of production of the maximum amount of reserves from the
reservoir. The Company is hopeful that production from these new wells will be
in line with the production from its more productive existing wells in the Swan
Creek Field and will have a noticeable effect on increasing the total production
from the Field. Although no assurances can be made, the Company believes that it
will either be able to resolve the Bank One dispute or obtain additional or
replacement financing to allow drilling to increase, and that once new wells are
drilled, production from the Swan Creek Field will increase. However, no
assurances can be made that such financing will be obtained or that overall
produced volumes will increase.
Similarly, when funding for additional drilling becomes available, the
Company plans to drill wells in five new locations it has identified in Ellis
and Rush Counties, Kansas on its existing leases in response to drilling
activity in the area establishing new areas of oil production. Although the
Company successfully drilled the Dick No. 7 well in Kansas in 2001 and completed
the well as an oil well, it was not able to drill any new wells in Kansas in
2002 due to lack of funds available for such drilling caused by the Bank One
situation. As with Tennessee, the Company is hopeful that
40
once the Bank One matter is resolved it will be able to resume drilling and well
workovers in Kansas to maximize production from the Kansas Properties.
As of December 31, 2002, the Company had total stockholders' equity of
$14,210,623 on total assets of $32,584,391. The Company has a net working
capital deficiency at December 31, 2002 of $7,998,835 as compared to a net
deficiency of $6,326,204 at December 31, 2001. This working capital deficiency
arises primarily from the acceleration of $6,000,000 of the Bank One credit
facility debt discussed above.
Net cash used in operating activities increased from $221,176 in 2001 to
$566,017 in 2002. The Company's net loss in 2002 increased to $3,154,555 from
$2,262,787 in 2001. The impact on cash used due to the net loss for 2001 was
offset by non-cash depletion, depreciation and amortization of $2,413,597. Cash
flow from working capital items in 2002 was $126,321 as compared to $232,338 in
2001. This resulted from increases in accounts payable of $188,597, and an
increase in accrued liabilities of $31,805 and an increase in other current
assets of $58,000, partially offset by an increase in accounts receivable of
$69,192 and an increase in inventory of $103,384.
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 investing activities amounted to $2,889,937 for 2002
compared to net cash used in the amount of $9,408,684 for 2001. The decrease in
net cash used for investing activities during 2002 is primarily attributable to
the construction of Phase II of the pipeline of $4,213,095 in 2001 as compared
to $841,750 in 2002, additions to oil and gas properties of $4,821,883 in 2001
as compared to $1,982,529 in 2002.
Net cash used in investing activities amounted to $9,408,684 for 2001 as
compared to $8,936,863 for 2000. The 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 provided by financing activities decreased to $3,246,633 in 2002
from $8,419,336 in 2001. This was due to the Company's inability to enter into
new financing
41
arrangements in 2002 as a result of its dispute with Bank One as discussed
above. In 2001 the primary sources of financing includes proceeds from
borrowings of $10,442,068 as compared to $2,063,139 in 2002, private placements
of common stock of $3,900,000 in 2001 as compared to $2,677,000 in 2002 and
convertible redeemable preferred stock of $l,591,150 in 2001 as compared to
$1,303,168 in 2002 and proceeds from exercise of options of $2,341,000 in 2001
as compared to zero in 2002 as the market price of the Company's stock fell
below the exercise price of the earlier granted options. The primary use of cash
in financing activities in 2001 was the use of the funds received from Bank One
to repay the Company's prior borrowings of $8,833,325 as compared to 2002 when
cash from financing activities of $2,378,273 was used primarily to make payments
to Bank One in 2002 and for working capital.
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
$4,245,700 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.
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.
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 $1,982,529,
$4,821,883 and $1,456,996 of these costs in 2002, 2001 and 2000, respectively.
Costs, however, associated with
42
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/DEPLETION DEPRECIATION
AND AMORTIZATION OF OIL AND GAS PROPERTIES
The capitalized costs of oil and gas properties, plus estimated future
development costs relating to proved reserves and estimated costs of plugging
and abandonment, net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The costs of unproved
properties are excluded from amortization until the properties are evaluated,
subject to an annual assessment of whether impairment has occurred.
The Company's proved oil and gas reserves as at December 31, 2002 were
estimated by Ryder Scott, L.P., Petroleum Consultants. The Company's discounted
present value of its proved oil and gas reserves requires subjective judgments.
Estimates of the Company's reserves are in part forecasts based on engineering
data, projected future rates of production and timing of future expenditures.
The process of estimating oil and gas reserves requires substantial judgment,
resulting in imprecise determinations, particularly for new discoveries.
Different reserve engineers may make different estimates of reserve quantities
based on the same data. The passage of time provides more qualitative
information regarding estimates of reserves and revisions are made to prior
estimates to reflect updated information. Given the volatility of oil and gas
prices, it is also reasonably possible that the Company's estimate of discounted
net cash flows from proved oil and gas reserves could change in the near term.
If oil and gas prices decline significantly this will result in a reduction of
the valuation of the Company's reserves. This past year, Ryder Scott based on
production results and the increase of oil and gas prices, increased the
Company's estimated value of reserves of gas in the Swan Creek Field from its
reserve report for the year ended December 31, 2001. See, "Item 2 - Description
of Property - Reserve Analysis".
CONTINGENCIES
The Company accounts for contingencies in accordance with Financial
Accounting Standards Board Statement of Financial Accounting Standards ("SFAS")
No. 5, "Accounting Contingencies." SFAS No. 5 requires that we record an
estimated loss from a loss contingency when information available prior to the
issuance of the Company's financial statements indicate that it is probable an
asset has been impaired or a liability has been incurred at the date of the
financial statements and the amount of the loss can be reasonably estimated.
Accounting for contingencies such as environmental, legal and income tax matters
requires management of the Company to use its judgment. While management of the
Company believes that the Company's accrual for these matters are adequate, if
the actual loss from a loss contingency is significantly
43
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."
RECENT ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") 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 was 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 did not have an
effect on the Company's financial position or results of operations.
In 2001, the FASB issued SFAS No.143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires companies to record
the present value of obligations associated with the retirement of tangible
long-lived assets in the period in which it is incurred. The liability is
capitalized as part of the related long-lived asset's carrying amount. Over
time, accretion of the liability is recognized as an operating expense and the
capitalized cost is depreciated over the expected useful life of the related
asset. The Company's asset retirement obligations relate primarily to the
plugging dismantlement, removal, site reclamation and similar activities of its
oil and gas properties. Prior to adoption of this statement, such obligations
were accrued ratably over the productive lives of the assets through its
depreciation, depletion and amortization for oil and gas properties without
recording a separate liability for such amounts. The Company has adopted SFAS
143 beginning on January 1, 2003; however, the effect of adoption of this
statement on future results of operations or financial position has not yet been
determined by management.
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 became effective for the
Company's fiscal year beginning January 1, 2003. Management does not expect that
adoption of this standard will have a material impact on the Company's financial
position or results of operations.
44
The FASB issued Statement No. 145, Rescission of FASB Statements No. 4, 44,
and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on April
30, 2002. SFAS No.145 will be effective for fiscal years beginning after May 15,
2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses From
Extinguishment of Debt, and requires that all gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in APB No. 30. Applying APB No. 30 will distinguish
transactions that are part of an entity's recurring operations from those that
are unusual or infrequent or that meet the criteria for classification as an
extraordinary item. Any gain or loss on extinguishment of debt that was
classified as an extraordinary item in prior periods presented that does not
meet the criteria in APB No. 30 for classification as an extraordinary item must
be reclassified. There is no current impact of adoption on the Company's
financial position or results of operation.
The FASB issued Statement No. 146, Accounting for Costs Associated with
Exit or Disposal Activities, in June 2002. SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs incurred in a Restructuring). SFAS No. 146 applies to
costs incurred in an "exit activity", which includes, but is not limited to,
re-structuring, or a "disposal activity" covered by SFAS No. 144.
SFAS No. 146 requires that a liability for a cost associated with an exit
or disposal activity be recognized when the liability is incurred. Previously,
under Issue 94-3, a liability for an exit cost was recognized at the date of an
entity's commitment to an exit plan. Statement No. 146 also establishes that
fair value is the objective for initial measurement of the liability. The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002. Management does not expect that adoption
of this standard will have a material effect on the Company's financial position
or results of operation.
In November 2002, the FASB issued Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others, an interpretation of FASB Statements No.5,
57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation
elaborates on the disclosures to be made by a guarantor in its interim and
annual financial statements about its obligations under guarantees issued. The
Interpretation also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken. The initial recognition and measurement provisions of the
Interpretation are applicable to guarantees issued or modified after December
31, 2002. The Company has not guaranteed the debts of others, therefore, this
interpretation is not expected to have a material effect on the Company's
financial statements.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment of FASB Statement
No.123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based
Compensation, to provide alternative methods of transition for a voluntary
change to the fair value method
45
of accounting for stock-based employee compensation. In addition, this Statement
amends the disclosure requirements of Statement No. 123 to require prominent
disclosures in both annual and interim financial statements. Management has
adopted certain of the disclosure modifications are required for fiscal years
ending after December 15, 2002 and are included in the notes to the accompanying
consolidated financial statements.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51. Interpretation No. 46 requires a company to consolidate a variable
interest entity if the company has a variable interest (or combination of
variable interests) that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur, or both. A direct or indirect ability to make decisions that
significantly affect the results of the activities of a variable interest entity
is a strong indication that a company has one or both of the characteristics
that would require consolidation of the variable interest entity. Interpretation
No. 46 also requires additional disclosures regarding variable interest
entities. The new interpretation is effective immediately for variable interest
entities created after January 31, 2003, and is effective in the first interim
or annual period beginning after June 15, 2003, for variable interest entities
in which a company holds a variable interest that it acquired before February 1,
2003. Management does not expect that adoption of this interpretation will have
a material effect on the Company's financial position or results of operation.
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 $18.56 per barrel to a high
of $27.49 per barrel during 2002. Gas price realizations ranged from a monthly
low of $1.91 per Mcf to a monthly high of $4.01 per Mcf during the same period.
As required by its Credit Agreement with Bank One, the Company entered into
hedge agreements on December 28, 2001 on notional volumes of oil and natural gas
production for the first six 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 the associated production occurs. Notional volumes associated with
the Company's derivative contracts are 27,000 barrels and 630,000 MMBTU's for
oil and natural gas, respectively. The Company does not generally hold or issue
derivative instruments for trading purposes. These hedge agreements expired in
June 2002
46
and have not been renewed. Hedging activities resulted in a loss to the Company
of approximately $118,000 for the year ended December 31, 2002.
INTEREST RATE RISK
At December 31, 2002, the Company had debt outstanding of approximately
$9.9 million. The interest rate on the revolving credit facility of $7.5 million
is variable based on the financial institution's prime rate plus 0.25%. The
remaining debt of $2.4 million has fixed interest rates ranging from 6% to
11.95%. As a result, the Company's annual interest costs in 2002 fluctuated
based on short-term interest rates on approximately 78% of its total debt
outstanding at December 31, 2002. The impact on interest expense and the
Company's cash flows of a 10 percent increase in the financial institution's
prime rate (approximately 0.5 basis points) would be approximately $32,000,
assuming borrowed amounts under the credit facility remain at $7.5 million. The
Company did not have any open derivative contracts relating to interest rates at
December 31, 2002.
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.
47
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
48
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
- ---- ---- -----------
Stephen W. Akos Director 2/28/03
8000 Maryland Avenue
St. Louis, MO 63105
Joseph E. Armstrong Director 3/13/97
4708 Hilldale Drive
Knoxville, TN 37914
Jeffrey R. Bailey Director; 2/28/03
2306 West Gallaher Ferry President 6/17/02
Knoxville, TN 37932
John A. Clendening Director 2/28/03
1031 Saint Johns Drive
Maryville, TN 37801
Robert L. Devereux Director 2/28/03
10 South Brentwood Blvd.
St. Louis, MO 63105
Bill L. Harbert . Director 4/2/02
820 Shaders Creek Pkway
Birmingham, AL 35209
Peter E. Salas Director 10/8/02
129 East 17th Street
New York, NY 10003
49
Charles M. Stivers Director 9/28/01
420 Richmond Road
Manchester, KY 40962
Richard T. Williams Director; 6/28/02
4472 Deer Run Drive Chief Executive 2/3/03
Louisville, TN 37777 Officer
Mark A. Ruth Chief Financial 12/14/98
9400 Hickory Knoll Lane Officer
Knoxville, TN 37922
Robert M. Carter President Tengasco 6/1/98
760 Prince George Parish Drive Pipeline Corporation
Knoxville, TN 37931
Cary V. Sorensen General Counsel; 07/9/99
509 Bretton Woods Dr. Secretary
Knoxville, TN 37919
Sheila F. Sloan Treasurer 12/4/96
121 Oostanali Way
Loudon, TN 37774
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
In fiscal 2002, Malcolm E. Ratliff, formerly a Director of the Company and
its Chief Executive Officer in 2002, failed to timely file one Form 4 Report
involving two transactions. Mr. Ratliff also recently filed an untimely Form 5
Report which indicated he failed to file Form 4 Reports for two transactions,
one in October 2002 and the other in December 2002. Benton L. Becker, who was a
Director of the Company in 2002, also failed to timely file one Form 4 Report
involving three transactions.
BUSINESS EXPERIENCE
DIRECTORS
Stephen W. Akos is 49 years old. He has over twenty years experience in the
financial services industry with an expertise in fixed income securities. Since
August of 2000, he has been First Vice President, Institutional Fixed Income
Sales, Robert W. Baird & Co., St. Louis, Missouri. Prior to 2000, he held
executive positions with Mercantile Bank and Mark Twain Bank since 1993. Before
1993 he was a broker and
50
held a series of executive positions at brokerage firms Dean Witter, Shearson
Lehman Hutton, Drexel Burnham Lambert, and Kidder Peabody in St. Louis. He
received an MBA in Finance from Washington University in 1979, and a B.S. in
Business Administration, Accounting, from Washington University in 1976. He has
been a shareholder of the Company for approximately six years. He was elected as
a Director of the Company on February 28, 2003.
Joseph Earl Armstrong is 46 years old and a resident of Knoxville,
Tennessee. He is a graduate of the University of Tennessee and Morristown
College where he received a Bachelor of Science Degree in Business
Administration. From 1988 to the present, he has been an elected State
Representative for Legislative District 15 in Tennessee. From 1994 to the
present he has been in charge of government relations for the Atlanta Life
Insurance Co. From 1981 to 1994 he was a District Manager for the Atlanta Life
Insurance Co. He has served as Director of the Company since 1997.
Jeffrey R. Bailey is 45 years old. He graduated in 1980 from New Mexico
Institute of Mining and Technology with a B.S. degree in Geological Engineering.
Upon graduation he joined Gearhart Industries as a field engineer working in
Texas, New Mexico, Kansas, Oklahoma and Arkansas. Gearhart Industries later
merged with Halliburton Company. In 1993 after 13 years working in various field
operations and management roles primarily focused on reservoir evaluation, log
analysis and log data acquisition he assumed a global role with Halliburton as a
Petrophysics instructor in Fort Worth, Texas. His duties were to teach
Halliburton personnel and customers around the world log analysis and
competition technology and to review analytical reservoir problems. In this role
Mr. Bailey had the opportunity to review reservoirs in Europe, Latin America,
Asia Pacific and the Middle East developing a special expertise in carbonate
reservoirs. In 1997 he became technical manager for Halliburton in Mexico
focusing on finding engineering solutions to the production challenges of large
carbonate reservoirs in Mexico. He joined the Company as its Chief Geological
Engineer on March 1, 2002. He was elected as President of the Company on July
17, 2002 and as a Director on February 28, 2003.
Dr. John A. Clendening is 70 years old. He received B.S. (1958), M.S.
(1960) and Ph. D. (1970) degrees in geology from West Virginia University. He
was employed as a Palynologist-Coal Geologist at the West Virginia Geological
Survey from 1960 until 1968. He joined Amoco in 1968 and remained with Amoco as
a senior geological associate until 1972. Dr. Clendening has served as President
and other offices of the American Association of Stratigraphic Palynologists and
the Society of Organic Petrologists. From 1992 - 1998 he was engaged in
association with Laird Exploration Co., Inc. of Houston, Texas, directing
exploration and production in south central Kentucky. In 1999 he purchased all
the assets of Laird Exploration in south central Kentucky and operates
independently. While with Amoco Dr. Clendening was instrumental in Amoco's
acquisition in the early 1970's of large land acreage holdings in Northeast
Tennessee, based upon his geological studies and recommendations. His work led
directly to the discovery of what is now the Company's Paul Reed # 1 well. He
further recognized the area to have significant oil and gas potential and is
credited with discovery of the field which is now known as the Company's Swan
Creek Field. Dr. Clendening previously served as a Director of the
51
Company from September 1998 to August 2000. He was again elected as a Director
of the Company on February 28, 2003.
Robert L. Devereux is 42 years old. He graduated in 1982 from St. Louis
University with a Bachelor's Degree in Business Administration with a major in
finance. He received his law degree from St. Louis University in 1985. For the
past eighteen years, Mr. Devereux has been actively engaged in the practice of
law, specializing in commercial litigation. Since 1994, he has been a principal
in the law firm of Devereux Murphy LLC located in St. Louis, Missouri. For the
past eight years Mr. Devereux has also been a principal of and has served as the
Chief Executive Officer of Gateway Title Company, Inc. He was elected as a
Director of the Company on February 28, 2003.
Bill L. Harbert is 79 years old. He earned a B.S. degree in civil
engineering from Auburn University in 1948. In 1949 he was one of the founders
of Harbert Construction Company. He managed that company's construction
operations, both domestic and foreign, and served as its Executive
Vice-President until 1979. From 1979 until July, 1990 he served as President and
Chief Operating Officer and from July 1990 through December 1991 he served as
Vice Chairman of the Board of Harbert International, Inc. He then purchased a
majority of the international operations of Harbert International, Inc. and
formed Bill Harbert International Construction, Inc. He served as Chairman and
Chief Executive Officer of that corporation until retiring from the company in
2000. Mr. Harbert's companies built pipeline projects in the United States and
throughout the world. They also built many other projects including bridges,
commercial buildings, waste water treatment plants, airports, including an air
base in Negev, Israel and embassies for the United States government in, among
other places, Tel Aviv, Hong Kong, and Baku. Mr. Harbert has also served as
president (1979) and Director (1980) of the Pipe Line Contractors Association,
USA and for seven years as Director, Second Vice-President and First
Vice-President (2001-2002) of the International Pipe Line Contractors
Association. Mr. Harbert has been active in service to a variety of business
associations, charities and the arts in the Birmingham area for many years. He
was elected as a Director of the Company on April 2, 2002.
Peter E. Salas is 48 years old. He has been President of Dolphin Asset
Management Corp. and its related companies since he founded it in 1988. Prior to
establishing Dolphin, he was with J.P. Morgan Investment Management, Inc. for
ten years, becoming Co-manager, Small Company Fund and Director-Small Cap
Research. He received an A.B. degree in Economics from Harvard in 1976. Mr.
Salas was elected to the Board of Directors on October 8, 2002.
Charles M. Stivers is 40 years old. He is a Certified Public Accountant
with 18 years accounting experience. In 1984 he received a B.S. degree in
accounting from Eastern Kentucky University. From 1983 through July 1986 he
served as Treasurer and CEO for Clay Resource Company. From August 1986 through
August 1989 he served as a senior tax and audit specialist for Gallaher and
Company. From September 1989 to date he has owned and operated Charles M.
Stivers, C.P.A., a regional accounting firm. Mr. Stiver's firm specializes in
the oil and gas industry and has clients in eight states. The oil and gas work
performed by his firm includes
52
all forms of SEC audit work, SEC quarterly financial statement filings, oil and
gas consulting work and income tax services. Mr. Stiver's firm has also
represented oil and gas companies with respect to Federal and State income tax
disputes in 15 states over the past 12 years. In September 2001, he was elected
as a director of the Company and is the chairman of the Company's audit
committee.
Dr. Richard T. Williams is 52 years old. He has been a member of the
faculty of the Department of Geological Sciences at The University of Tennessee
in Knoxville, Tennessee, since 1987, after holding faculty positions at West
Virginia University and the University of South Carolina since 1979. He has been
engaged in reflection seismology and geophysical studies in the Appalachian
Overthrust since 1980. He earned his Ph.D. in Geophysics from Virginia Tech in
1979. Dr. Williams was elected to the Board of Directors of the Company
effective June 28, 2002. He was appointed Chief Operating Officer of the Company
on January 10, 2003, and on February 3, 2003, he was elected Chief Executive
Officer of the Company.
OFFICERS
Mark A. Ruth is 44 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 66 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 54 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
53
been continuously engaged in the practice of law in Houston, Texas relating to
the energy industry since 1977, both in private law firms and a corporate law
department, most recently serving for seven years as senior counsel with the
litigation department of Enron Corp. before entering private practice in June,
1996. He has represented virtually all of the major oil companies headquartered
in Houston and all of the operating subsidiaries of Enron Corp., as well as
local distribution companies and electric utilities in a variety of litigated
and administrative cases before state and federal courts and agencies in five
states. These matters involved gas contracts, gas marketing, exploration and
production disputes involving royalties or operating interests, land titles, oil
pipelines and gas pipeline tariff matters at the state and federal levels, and
general operation and regulation of interstate and intrastate gas pipelines. He
has served as General Counsel of the Company since July 9, 1999.
Sheila F. Sloan is 47 years old. She graduated from South Lake High School
located in St. Clair Shores, Michigan in 1972. From 1981 to 1985 she worked as a
purchasing agent for Sequoyah Land Company located in Madisonville, Tennessee.
From 1990 to 1995 she managed the Form U-3 Weight Loss Centers in Knoxville,
Tennessee. She has been with the Company since January 1996. On December 4, 1996
she was elected as the Company's Treasurer.
COMMITTEES
The Company's Board has operating audit, stock option, compensation, field
safety and frontier exploration committees. Charles M. Stivers, Stephen W. Akos
and John A. Clendening are the members of the Company's Audit Committee. Mr.
Stivers is the Chairman of this Committee and has also been designated by the
Company as the financial expert of the Audit Committee. Robert L. Devereux, John
A. Clendening and Mr. Akos comprise the stock option committee with Mr. Devereux
acting as Chairman; Messrs. Akos, Stivers and Clendening comprise the
compensation committee with Mr. Clendening acting as Chairman; Richard T.
Williams, Jeffrey R. Bailey and Joseph Earl Armstrong comprise the field safety
committee; and Messrs. Williams, Bailey and Clendening comprise the frontier
exploration committee.
FAMILY RELATIONSHIPS
There are no family relationships between any of the present directors or
executive officers of the Company.
INVOLVEMENT IN CERTAIN LEGAL PROCEEDINGS
To the knowledge of management, during the past five years, no present or
former director, executive officer, affiliate or person nominated to become a
director or an executive officer of the Company:
54
(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, 2002, December 31, 2001 and December 31, 2000. None of the
Company's other executive officers earned compensation in excess of $100,000 per
annum for services rendered to the Company in any capacity during those periods.
55
SUMMARY COMPENSATION TABLE
-----------LONG TERM AWARDS-----
ANNUAL COMPENSATION -----------AWARDS----PAYOUTS
- ------------------------------------------------------------------------------------------------------------------------------------
Name and YEAR SALARY ($) BONUS ($) OTHER ANNUAL RESTRICTED SECURITIES PAYOUTS ALL OTHER
Principal Position COMPENSATION STOCK UNDERLYING COMPEN-
($) AWARDS($) OPTIONS SATION
/SARS(#)
- ------------------------------------------------------------------------------------------------------------------------------------
Malcolm E. Ratliff, 2002 $80,000 $-0- $ -0- -0- 59,0628 -0- -0-
Chief Executive Officer(7) 2001 $80,000 $-0- $1,000 -0- 52,500 -0- -0-
2000 $70,000 $-0- $ 500 -0- 52,500 -0- -0-
- ------------------------------------------------------------------------------------------------------------------------------------
- --------------------------
(7) Malcolm E. Ratliff served as the Company's Chief Executive Officer
throughout 2002. Richard T. Williams, the Company's current Chief Executive
Officer replaced Mr. Ratliff on February 3, 2003.
(8) Number of shares underlying options has been retroactively adjusted for a 5%
stock dividend declared by the Company as of September 4, 2001.
56
OPTION GRANTS FOR FISCAL 2002
During fiscal year ended December 31, 2002 the Company granted an option to
the Chief Executive Officer to purchase 6,562 shares of the Company's common
stock at a price of $2.86 per share. The option was for a period of three years
commencing on August 5, 2002. None of the Company's other executive officers
earned compensation in excess of $100,000 per annum for services rendered to the
Company in any capacity during the fiscal year ended December 31, 2002.
AGGREGATE OPTION EXERCISES FOR FISCAL 2002
AND YEAR END OPTION VALUES
--------------------------------------------------------
NUMBER OF SECURITIES(9) VALUE(10) of Unexercised
Underlying Unexercised In-the-Money
Options/SARs at Options/SARs at
December 31, 2002 December 31, 2002
- --------------------------------------------------------------------------------------------------------------------
NAME SHARES ACQUIRED VALUE ($) EXERCISABLE/ EXERCISABLE/
ON EXERCISE REALIZED(11) UNEXERCISABLE UNEXERCISABLE
- --------------------------------------------------------------------------------------------------------------------
MALCOLM E. RATLIFF -0- -0- 59,062/-0- $-0-/-0-
- --------------------------------------------------------------------------------------------------------------------
No options were exercised during fiscal year ended December 31, 2002 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 is considering adopting a 401(k)
plan and full liability insurance for directors and executive officers. However,
there are no immediate plans to do so at this time.
COMPENSATION OF DIRECTORS
The Board of Directors has resolved to compensate members of the Board of
Directors for 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.
- --------------------------
(9) 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.
(10) 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 $1.10 per share on December 31, 2002, as reported
by The American Stock Exchange. The exercise price of the unexercised options
granted to Malcolm E. Ratliff, the Chief Executive Officer of the Company, were
$8.69 and $2.86 per share. As a result, the unexercised options have a negative
value.
(11) 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.
57
Members of the Board of Directors may also be requested to perform
consulting or other professional services for the Company from time to time. The
Board of Directors has reserved to itself the right to review all directors'
claims for compensation on an ad hoc basis.
Directors who are on the Company's Audit, Compensation and Stock Option
Committees are independent and therefore, do not receive any consulting,
advisory or compensatory fees from the Company. However, such Board members may
receive fees from the Company for their services on those committees. The
Company intends to implement a plan for the payment of those committee members
for their services on an annual basis.
EMPLOYMENT CONTRACTS
The Company has entered into an employment contract with its Chief
Executive Officer, Richard T. Williams for a period of two years through
December 31, 2004 at an annual salary of $80,000. There are presently no other
employment contracts relating to any member of management. However, depending
upon the Company's operations and requirements, the Company may offer long term
contracts to directors, executive officers or key employees in the future.
COMPENSATION COMMITTEE INTERLOCKING
AND INSIDER PARTICIPATION
There are no interlocking 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
58
of March 3, 2003 with these computations being based upon 11,927,004 shares of
common stock being outstanding as of that date and as to each shareholder, as it
may pertain, assumes the exercise of options or warrants or the conversion of
convertible debt or preferred stock granted or held by such shareholder as of
March 3, 2003.
FIVE PERCENT STOCKHOLDERS(12)
NUMBER OF SHARES PERCENT OF
NAME AND ADDRESS TITLE BENEFICIALLY OWNED CLASS
- ---------------- ----- ------------------ -----
Malcolm E. Ratliff Stockholder 2,736,549(13) 22.8%
1200 Scott Lane
Knoxville, TN 37922
Dolphin Offshore Stockholder 2,036,613(14) 16.7%
Partners, L.P.
129 East 17th Street
New York, NY 10003
Bill L. Harbert Stockholder/ 1,489,496(15) 12.4%
820 Shaders Creek Pkwy. Director
Birmingham, AL 35209
DIRECTORS AND OFFICERS(16)
NUMBER OF SHARES PERCENT OF
NAME AND ADDRESS TITLE BENEFICIALLY OWNED CLASS
- ---------------- ----- ------------------ -----
Stephen W. Akos Director 23,439(17) Less than 1%
8000 Maryland Avenue
St. Louis, MO 63105
Joseph Earl Armstrong Director 57,450(18) Less than 1%
4708 Hilldale Drive
Knoxville, TN 37914
- --------------------------
(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) Malcolm E. Ratliff, formerly the Company's Chief Executive Officer and
Chairman of the Board of Directors and a former Director of the Company, is the
sole shareholder and President of Industrial Resources Corporation (" IRC").
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 include 80,171 shares owned
directly and an option to purchase 59,062 shares held by Malcolm E. Ratliff,
1,849,744 shares owned by IRC, 716,072 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
or any entity of which he is the controlling person. The shares listed also do
not include 373,900 shares directly owned by Dolphin Offshore Partners, L.P.
("Dolphin") which Dolphin granted IRC an option to purchase commencing April 11,
2003 and expiring on May 21, 2003 at a price of $2.386 per share. The general
partner and controlling person of Dolphin is Peter Salas, a Director of the
Company. In the event IRC does not exercise the option, Dolphin has the right to
require IRC to purchase from it the same number of shares that are the subject
of the option (373,900) at a price of $2.495 per share.
(14) Consists of 1,739,720 shares held by Dolphin Offshore Partners, L.P.
("Dolphin") of which Peter E. Salas, a Director of the Company, is the general
partner and controlling person; a warrant held by Dolphin to purchase 10,500
shares at $7.98 per share; 173,611 shares underlying a promissory convertible
note held by Dolphin; and, 112,782 shares underlying 9,000 shares of the
Company's Series B 8% Cumulative Convertible Preferred Stock held directly which
is convertible into the Company's Common Stock at the rate of $7.98 per
share.The shares listed include 373,900 shares held directly by Dolphin as to
which Dolphin granted an option to Industrial Resources Corporation ("IRC") to
purchase commencing on April 11, 2003 and expiring on May 21, 2003 at a price of
$2.386 per share. Malcolm E. Ratliff, a Director of the Company and formerly the
Company's Chief Executive Officer and Chairman of the Board, is the sole
shareholder and President of IRC. If the option is not exercised, Dolphin has
the right to require IRC to purchase from it the same number of shares that are
the subject of the option (373,900) at a price of $2.495 per share.
(15) Consists of 1,404,942 shares held directly, 71,429 shares underlying 5,000
shares of the Company's Series A 8% Cumulative Convertible Preferred Stock held
directly which is convertible into the Company's Common Stock and an option to
purchase 13,125 shares.
(16) 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.
(17) Consists of 14,081 shares held directly (certain of which are jointly owned
with spouse) and 9,358 shares underlying convertible promissory notes owned with
his spouse and by a limited partnership. Shares underlying note held by limited
partnership has been adjusted to reflect his ownership interest in the limited
partnership.
(18) Consists of 4,950 shares held directly and options to purchase 52,500
shares.
59
Jeffrey R. Bailey Director; 18,125(19) Less than 1%
2306 West Gallaher Ferry President
Knoxville, TN 37932
John A. Clendening Director -0- -0-
1031 Saint Johns Drive
Maryville, TN 37801
Robert L. Devereux Director 56,882(20) Less than 1%
10 South Brentwood Blvd.
St. Louis, MO 63105
Bill L. Harbert Director 1,489,496(21) 12.4%
820 Shaders Creek Pkwy.
Birmingham, AL 35209
Peter E. Salas Director 2,036,613(22) 16.7%
129 East 17th Street
New York, NY 10003
Charles M. Stivers Director 13,125(23) Less than 1%
420 Richmond Road
Manchester, KY 40962
Richard T. Williams Director; 13,125(24) Less than 1%
4477 Deer Run Drive Chief Executive
Louisville, TN Officer
Robert M. Carter President 68,071(25) Less than 1%
760 Prince Georges Parish Tengasco Pipeline
Knoxville, TN 37922 Corporation
- --------------------------
(19) Consists of 5,000 shares held directly and an option to purchase 13,125
shares.
(20) Consists of 34,562 shares held directly with his spouse; 12,448 shares
underlying a convertible note held with his spouse; 6,753 shares owned by a
limited liability company; and, 3119 shares underlying a convertible promissory
note held by a limited liability company. Shares owned by the limited liability
company and underlying note held by the limited liability company have been
adjusted to reflect his ownership interest in the limited liability company.
(21) Consists of 1,404,942 shares held directly, 71,429 shares underlying 5,000
shares of the Company's Series A 8% Cumulative Convertible Preferred Stock held
directly which is convertible into the Company's Common Stock at the rate of
$7.00 per share and an option to purchase 13,125 shares.
(22) Consists of 1,739,720 shares held by Dolphin Offshore Partners, L.P.
("Dolphin") of which Peter E. Salas is the general partner and controlling
person; a warrant held by Dolphin to purchase 10, 500 shares at $7.98 per share;
173,611 shares underlying a promissory convertible note held by Dolphin; and,
112,782 shares underlying 9,000 shares of the Company's Series B 8% Cumulative
Convertible Preferred Stock held directly which is convertible into the
Company's Common Stock at the rate of $7.98 per share. The shares listed include
373,900 shares held directly by Dolphin as to which Dolphin granted an option to
Industrial Resources Corporation ("IRC") to purchase commencing on April 11,
2003 and expiring on May 21, 2003 at a price of $2.386 per share. Malcolm E.
Ratliff, a Director of the Company and formerly the Company's Chief Executive
Officer and Chairman of the Board, is the sole shareholder and President of IRC.
If the option is not exercised, Dolphin has the right to require IRC to purchase
from it the same number of shares that are the subject of the option (373,900)
at a price of $2.495 per share.
(23) Consists of shares underlying an option.
(24) Consists of shares underlying an option.
(25) Consists of 7,696 shares held directly and options to purchase 60,375
shares.
60
Mark A. Ruth Chief Financial 45,937(26) Less than 1%
9400 Hickory Knoll Lane Officer
Knoxville, TN 37931
Cary V. Sorensen General Counsel; 39,375(27) Less than 1%
509 Bretton Woods Dr. Secretary
Knoxville, TN 37919
Sheila F. Sloan Treasurer 21,787(28) Less than 1%
121 Oostanali Way
Loudon, TN 37774
All Officers and 3,883,425(29) 30.8%
Directors as a group
CHANGES IN CONTROL
Except as indicated below, to the knowledge of the Company's management,
there are no present arrangements or pledges of the Company's securities which
may result in a change in control of the Company.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TRANSACTIONS WITH MANAGEMENT AND OTHERS
Except as set forth hereafter, there have been no material transactions,
series of similar transactions or currently proposed transactions during 2002,
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.
- --------------------------
(26) Consists of shares underlying options.
(27) Consists of shares underlying options.
(28) Consists of 2,100 shares held directly and options to purchase 19,687
shares.
(29) Consists of shares held directly and indirectly by management, shares held
by Dolphin, 270,374, shares underlying options, 10,500 shares underlying
warrants, 198,536 shares underlying convertible promissory notes and 182,411
shares underlying convertible preferred stock.
61
On January 21, 2002 and April 9, 2002, Bill Harbert, who owns more than ten
percent of the Company's outstanding Common Stock and is now a Director of the
Company, but was not at that time, in two private placements purchased 100,000
shares of the Company's common stock on each of those dates, at prices of $6.32
and $4.80 per share, respectively. The proceeds from these private placements
were used as working capital to fund the Company's day to day operations.
On October 7, 2002, Dolphin Offshore Partners, L.P. ("Dolphin) which owns
more than ten percent of the Company's outstanding Common Stock and whose
general partner, Peter E. Salas, is a Director of the Company, in consideration
of a loan to the Company was issued an unsecured convertible promissory note by
the Company in the principal amount of $500,000 bearing 8% interest, with
payments of interest only payable quarterly and the principal payable January 4,
2004. The principal amount of the note is convertible into Common Stock of the
Company at the rate of $2.88 per share. The proceeds from this note were used to
provide working capital for the Company's operations.
In August 2002, Dolphin purchased 650,000 shares of the Company's Common
Stock in an open market transaction. In connection with that purchase, Dolphin
entered into an agreement on which was later amended on October 11, 2002 with
Industrial Resources Corporation ("IRC"), which owns more than ten percent of
the Company's outstanding Common Stock and whose sole shareholder and President,
Malcolm E. Ratliff, was at the time of this transaction the Company's Chief
Executive Officer and a Director of the Company. Pursuant to that agreement,
Dolphin granted IRC an option commencing on April 11, 2003 and expiring on May
12, 2003 to purchase up to 373,900 shares of the Company's Common Stock that had
been purchased by Dolphin at a price of $2.386 per share, and if the option is
not exercised during the option period IRC is then required to purchase from
Dolphin the same number shares that had been the subject of the option at price
of $2.495 per share. The Company is not a party to the agreement between IRC and
Dolphin concerning shares of the Company owned by Dolphin, and there is no
effect upon the Company based in any way upon the performance or nonperformance
of that agreement.
On December 4, 2002 , Dolphin loaned the Company the sum of $250,000 which
funds were used to pay the principal and interest due that month from the
Company to Bank One and to provide working capital for the Company. The Company
issued a promissory note to Dolphin bearing interest at the rate of 12% per
annum, with payments of interest only payable quarterly and the principal
balance payable on January 4, 2004.
On January 8, 2003, Bill Harbert purchased 227,275 shares of the Company's
Common Stock from the Company in a private placement at a price of $1.10 per
share. The proceeds from this sale were used by the Company to pay the principal
and interest due to Bank One for January, 2003 and to provide working capital
for the Company's operations.
62
On February 3, 2003 and February 28, 2003, Dolphin loaned the Company the
sum of $250,000 on each such date which the Company used to pay the principal
and interest due to Bank One for February and March 2003 and for working
capital. Each of these loans is evidenced by a separate promissory note each
bearing interest at the rate of 12% per annum, with payments of interest only
payable quarterly and the principal balance payable on January 4, 2004.
Each of the three loans made by Dolphin set forth above are secured by an
undivided 10% interest in the Company's Tennessee and Kansas pipelines.
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.
ITEM 14 CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Within the past 90 days, the Company's management, including its Chief
Executive Officer and Chief Financial Officer, has conducted an evaluation of
the effectiveness of the design and operation of the Company's disclosure
controls and procedures pursuant to Rule 13a-14 and 15d-14 under the Securities
Exchange Act of 1934, as amended. Based on that evaluation, the Company's Chief
Executive Officer and Chief Financial Officer believe:
The Company's disclosure controls and procedures are designed to ensure
that information required to be disclosed by the Company in the reports it files
or submits under the Securities Exchange Act of 1934, as amended, including this
Report, is recorded, processed, summarized and reported within the time periods
specified in the SEC's rules and forms; and
The Company's disclosure controls and procedures were effective to ensure
that material information was accumulated and communicated to management,
including the
63
Company's Chief Executive Officer and Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure.
CHANGES IN INTERNAL CONTROLS
There have been no significant changes in internal controls, or in factors
that could significantly affect internal controls, subsequent to the date the
Company's Chief executive Officer and Chief Financial Officer completed their
evaluation, nor were there any significant deficiencies or material weaknesses
in the Company's internal controls. As a result, no corrective actions were
required or taken.
PART IV
ITEM 15 EXHIBITS AND REPORTS
1. Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Loss
Consolidated Statements of Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Exhibits.
(a) - The following documents heretofore filed by the Company with the
commission are hereby incorporated by reference herein from:
(i) Registration Statement on Form 10-SB filed with the Commission August 7,
1997 (Registration No. 0-29386)
Exhibit Number and Description
3.1 Initial Articles of Incorporation
3.2 Bylaws
3.3 Articles of Amendment dated April 12, 1966
3.4 Articles of Amendment dated July 12, 1984
3.5 Articles of Amendment dated December 18, 1991
3.6 Articles of Amendment dated September 11, 1992
3.7 Articles of Incorporation of the Tennessee of wholly-owned
subsidiary
64
3.8 Articles of Merger and Plan of Merger (taking
into account the formation of the Tennessee
wholly-owned subsidiary for the purpose of
changing the Company's domicile and effecting
reverse split)
5.1 Opinion of Robson & Miller, LLP
10.1(a) Purchase Agreement with IRC
10.1(b) Amendment to Purchase Agreement with IRC
10.1(c) General Bill of Sale and Promissory Note
10.2(a) Compensation Agreement - M. E. Ratliff
10.2(b) Compensation Agreement - Jeffrey D. Jenson
10.2(c) Compensation Agreement - Leonard W. Burningham
10.3 Agreement with The Natural Gas Utility District of
Hawkins County, Tennessee
10.4 Agreement with Powell Valley Electric Cooperative, Inc.
10.5 Agreement with Enserch Energy Services, Inc.
16.1 Letter of David T. Thomson, CPA, Regarding Change in Certifying
Accountant
16.2 Letter of Charles M. Stivers, CPA, Regarding Change in Certifying
Accountant
16.3 Letter of Price-Bednar, LLP, CPA, Regarding Change in Certifying
Accountant
23.1 Consent of Charles M. Stivers, CPA
23.2 Consent of David T. Thomson, CPA
23.3 Consent of BDO Seidman, LLP
23.4 Consent of Robson & Miller, LLP
99.1 Beech Creek Lease Schedule
99.2 Wildcat Lease Schedule
99.3 Burning Springs Lease Schedule
99.4 Fentress County Lease Schedule
99.5 Swan Creek Lease Schedule
99.6 Alabama Lease Schedule
99.7 Coburn Engineering Report dated June 18, 1997.
(ii) Amendment No. 1 to the Registration Statement on Form 10-SB filed with the
Commission December 11, 1997 (Registration No. 0-29386)
Exhibit Number and Description
5.1 Opinion of Robson & Miller, LLP
23.1 Consent of Charles M. Stivers, CPA
23.3 Consent of BDO Seidman, LLP
23.4 Consent of Robson & Miller, LLP
23.5 Consent of Coburn Petroleum Engineering Co.
65
(iii) Current Report on Form 8-K, Date of Report, February 27, 1998:
Exhibit Number and Description
2.1 Plan of Acquisition. Agreement dated December 18, 1997 between AFG
Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG
Energy, Inc.
(iii) Current Report on Form 8-KA, Date of Report, February 27, 1998:
Exhibit Number and Description
Financial Statements of Business Acquired (AFG Energy, Inc.)
Independent auditor's report, statement of revenues and direct
operating expenses and notes to financial statements of the
properties acquired by Tengasco, Inc. from AFG Energy, Inc. Pro
Forma Financial Information Pro forma combined statements of loss
for year ended December 31, 1997 for Tengasco, Inc. from AFG
Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG
Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG
Energy, Inc.
2.1(a) Exhibit A to Agreement dated December 18, 1997 between AFG
Energy, Inc. and Tengasco, Inc. regarding sale of assets of AFG
Energy, Inc.
(iv) Annual Report on Form 10-KSB, Date of Report, April 10, 1998
Exhibit Number and Description
10.6 Teaming Agreement between Operations Management International,
Inc. and Tengasco, Inc. dated March 12, 1997
10.7 Agreement for Transition Services between Operations Management
International, Inc. and Tengasco, Inc. regarding thEast Tennessee
Technology Park
99.8 Coburn Engineering Report dated February 18, 1997 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
99.9 Columbia Engineering Report dated March 2, 1997 (Paper copy filed
on Form SE pursuant to continuing hardship granted by Office of
EDGAR Policy)
66
(v) Annual Report on Form 10-KSB, Date of Report, April 14, 1999
Exhibit Number and Description
3.9 Amendment to the Corporate Charter dated June 24, 1998
3.10 Amendment to the Corporate Charter dated October 30, 1998
99.10 Coburn Engineering Report dated February 9, 1999 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
99.11 Columbia Engineering Report dated February 20, 1999 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
(vi) Current Report on Form 8-K, Date of Report, October 18, 1999:
Exhibit Number and Description
10.9 Amendment Agreement dated October 19, 1999 between Tengasco, Inc.
and The Natural Gas Utility District of Hawkins County, Tennessee
(vii) Current Report on Form 8-KA, Date of Report, November 18, 1999:
Exhibit Number and Description
10.10 Natural Gas Sales Agreement dated November 18, 1999 between
Tengasco, Inc. and Eastman Chemical Company
(viii) Annual Report on Form 10-KSB, Date of Report, April 12, 2000
Exhibit Number and Description
3.11 Amendment to the Corporate Charter filed March 17 , 2000
10.11 Agreement between A.M. Partners L.L.C. and Tengasco, Inc. dated
October 6, 1999
10.12 Agreement between Southcoast Capital L.L.C. and Tengasco, Inc.
dated February 25, 2000
10.13 Franchise Agreement between Powell Valley Utility District and
Tengasco, Inc. dated January 25, 2000
10.14 Amendment Agreement between Eastman Chemical Company and
Tengasco, Inc. dated March 27, 2000
99.12 Coburn Engineering Report dated March 30, 2000 (Paper copy filed
on Form SE pursuant to continuing hardship granted by Office of
EDGAR Policy)
67
99.13 Columbia Engineering Report dated January 31, 2000 (Paper copy
filed on Form SE pursuant to continuing hardship granted by
Office of EDGAR Policy)
(ix) Current Report on Form 8-K, Date of Report, August 16, 2000:
Exhibit Number and Description
10.15 Loan Agreement between Tengasco Pipeline Corporation and Morita
Properties, Inc. dated August 16, 2000.
10.15(a) Promissory note made by Tengasco Pipeline Corporation to Morita
Properties, Inc. dated August 16, 2000.
10.15(b) Throughput Agreement between Tengasco Pipeline Corporation and
Morita Properties, Inc. dated August 16, 2000.
10.16 Loan Agreement between Tengasco Pipeline Corporation and Edward
W.T. Gray III dated August 16, 2000.
10.16(a) Promissory note made by Tengasco Pipeline Corporation to Edward
W.T. Gray III dated August 16, 2000.
10.16(b) Throughput Agreement between Tengasco Pipeline Corporation and
Edward W.T. Gray III dated August 16, 2000.
10.17 Loan Agreement between Tengasco Pipeline Corporation and Malcolm
E. Ratliff dated August 16, 2000.
10.17(a) Promissory note made by Tengasco Pipeline Corporation to Malcolm
E. Ratliff dated August 16, 2000.
10.17(b) Throughput Agreement between Tengasco Pipeline Corporation and
Malcolm E. Ratliff dated August 16, 2000.
10.18 Loan Agreement between Tengasco Pipeline Corporation and Charles
F. Smithers, Jr. dated August 16, 2000.
10.18(a) Promissory note made by Tengasco Pipeline Corporation to Charles
F. Smithers, Jr.
10.18(b) Throughput Agreement between Tengasco Pipeline Corporation and
Charles F. Smithers dated August 16, 2000.
68
10.19 Loan Agreement between Tengasco Pipeline Corporation and Nick
Nishiwaki dated August 16, 2000.
10.19(a) Promissory note made by Tengasco Pipeline Corporation to Nick
Nishiwaki dated August 16, 2000.
10.19(b) Throughput Agreement between Tengasco Pipeline Corporation and
Nick Nishiwaki dated August 16, 2000.
(x) S-8 Registration Statement for shares to be purchased pursuant to options
granted pursuant to the Tengasco, Inc. Stock Incentive Plan dated October 25,
2000:
Exhibit Number and Description
4.1 Tengasco, Inc. Incentive Stock Plan
5.1 Opinion of Robson Ferber Frost Chan & Essner, LLP
23.1 Consent of BDO Seidman, LLP
23.2 Consent of Robson Ferber Frost Chan & Essner, LLP contained in
Exhibit No. 5.1
(xi) Annual Report on Form 10-KSB, Date of Report, April 10, 2001
Exhibit Number and Description
10.19 Memorandum Agreement between Tengasco, Inc. and The University of
Tennessee dated February 13, 2001
10.20 Natural Gas Sales Agreement between Tengasco, Inc. and BAE
SYSTEMS Ordnance Systems Inc. dated March 30, 2001
99.14 Ryder Scott Report
99.14(a) Consent of Ryder Scott Company
(xii) Quarterly Report on Form 10-Q, Date of Report, April 10, 2001
69
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
(xiii) Annual Report on Form 10-K, Date of Report, April 10, 2002
Exhibit Number and Description
99.15 Ryder Scott Report dated March 28, 2002
99.15(a) Consent of Ryder Scott Company
The following exhibits are filed herewith:
21 List of Subsidiaries
99.16 Certifications of Annual Report on Form 10-K for year ended
December 31, 2002 by Richard T. Williams Chief Executive Officer
and Mark A. Ruth Chief Financial Officer
99.17 Ryder Scott Report dated February 10, 2003
99.17(a) Consent of Ryder Scott Company
99.18 Consent of BDO Seidman, LLP
70
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities and
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Dated: March 31, 2003
TENGASCO, INC.
(Registrant)
By: /s/ RICHARD T. WILLIAMS
------------------------
Richard T. Williams,
Chief Executive Officer
By: /s/ MARK A. RUTH
---------------
Mark A. Ruth,
Principal Financial and Accounting Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in their capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/ STEPHEN W. AKOS Director March 31, 2003
- -------------------
Stephen W. Akos
/s/ JOSEPH EARL ARMSTRONG Director; Chairman of March 31, 2003
- -------------------------
Joseph Earl Armstrong the Board of Directors
/s/ /JEFFREY R. BAILEY Director; March 31, 2003
- ----------------------
Jeffrey R. Bailey President
/s/ JOHN A. CLENDENING Director March 31, 2003
- ----------------------
John A. Clendening
/s/ ROBERT L. DEVEREUX Director March 28, 2003
- ----------------------
Robert L. Devereux
71
/s/ BILL L. HARBERT Director March 28, 2003
- -------------------
Bill L. Harbert
/s/ PETER E. SALAS Director March 28, 2003
- -------------------
Peter E. Salas
/s/ CHARLES M. STIVERS Director March 31, 2003
- ----------------------
Charles M. Stivers
/s/ RICHARD T. WILLIAMS Director; March 31, 2003
- ----------------------- Chief Executive Officer
Richard T. Williams
/s/ MARK A. RUTH Principal Financial March 31, 2003
- ---------------------- and Accounting Officer
Mark A. Ruth
72
I, Richard T. Williams, certify that:
1. I have reviewed this annual report on Form 10-K of Tengasco, Inc.
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;
4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the Registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date'); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The Registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the Registrant's auditors and the audit
committee of the Registrant's board of directors (or persons performing the
equivalent function);
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the Registrant's ability to
record, process, summarize and report financial data and have identified for the
Registrant's auditors any material weakness in internal controls; and
(b) any fraud, whether or not material that involves the
management or other employees who have a significant role in the Registrant's
internal controls; and
6. The Registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Dated: March 31, 2003
/s/ RICHARD T. WILLIAMS
--------------------------
Richard T. Williams,
Chief Executive Officer
73
I, Mark A. Ruth, certify that:
1. I have reviewed this annual report on Form 10-K of Tengasco, Inc.
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;
3. Based on my knowledge, the financial statements, and other
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Registrant as of, and for, the periods presented in this annual report;
4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the Registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the Registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date'); and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The Registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the Registrant's auditors and the audit
committee of the Registrant's board of directors (or persons performing the
equivalent function);
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the Registrant's ability to
record, process, summarize and report financial data and have identified for the
Registrant's auditors any material weakness in internal controls; and
(b) any fraud, whether or not material that involves the
management or other employees who have a significant role in the Registrant's
internal controls; and
6. The Registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Dated: March 31, 2003
/s/ MARK A. RUTH
---------------------------------------------
Mark A. Ruth,
Principal Financial and Accounting Officer
74
TENGASCO, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
TENGASCO, INC.
AND SUBSIDIARIES
============================================================
CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
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
Consolidated Statements of cash flows F-8-9
Notes to consolidated financial statements F-10-37
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, 2002 and 2001, and the related consolidated
statements of loss, stockholders' equity and cash flows for each of the three
years in the period ended December 31, 2002. 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, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company has suffered recurring losses from operations
and has an accumulated deficit of $27,776,726. Additionally, during 2002, the
Company's primary lender has classified the remaining amount of $7,501,777 as
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 1. The financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
/s/ BDO Seidman LLP
Atlanta, Georgia
February 27, 2003
F-3
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
================================================================================
DECEMBER 31, 2002 2001
- -------------------------------------------------------------------------------------------------------
ASSETS (Note 1)
CURRENT
Cash and cash equivalents $ 184,130 $ 393,451
Investments 34,500 150,000
Accounts receivable 730,667 661,475
Participant receivables 70,605 84,097
Inventory 262,748 159,364
Current portion of loan fees, net of accumulated
amortization of $194,312 (Note 7) 323,856 -
- -------------------------------------------------------------------------------------------------------
TOTAL CURRENT ASSETS 1,606,506 1,448,387
OIL AND GAS PROPERTIES, net (on the basis
of full cost accounting) (Notes 4, 7 and 15) 13,864,321 13,269,930
COMPLETED PIPELINE FACILITIES, net of accumulated
depreciation of $729,043 and $220,374, respectively
(Notes 5 and 7) 15,372,843 15,039,762
OTHER PROPERTY AND EQUIPMENT, net (Notes 6 and 7) 1,685,950 1,680,104
RESTRICTED CASH - 120,872
LOAN FEES, net of accumulated amortization of
$13,384 and $21,590, respectively 40,158 496,577
OTHER ASSETS 14,613 72,613
- -------------------------------------------------------------------------------------------------------
$32,584,391 $32,128,245
======================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-4
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
================================================================================
DECEMBER 31, 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt (Notes 1 and 7) $ 7,861,245 $ 6,399,831
Accounts payable - trade 1,396,761 1,208,164
Accrued interest payable 61,141 54,138
Accrued dividends payable (Note 9) 254,389 112,458
Other accrued liabilities 31,805 -
- -----------------------------------------------------------------------------------------------------------------------
TOTAL CURRENT LIABILITIES 9,605,341 7,774,591
LONG TERM DEBT TO RELATED PARTIES (Note 7) 750,000 -
LONG TERM DEBT, less current maturities (Note 7) 1,256,209 3,902,757
- -----------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES 11,611,550 11,677,348
- -----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 1 and 8)
PREFERRED STOCK, $.0001 par value; authorized 25,000,000
shares (Note 9):
Series A 8% cumulative, convertible, mandatorily redeemable;
28,679 and shares outstanding; redemption value $2,867,900 2,867,900 2,867,900
Series B 8% cumulative, convertible, mandatorily redeemable;
27,550 shares outstanding; redemption value $2,755,000,
net of related commissions 2,591,150 2,591,150
Series C 6% cumulative, convertible, mandatorily redeemable;
14,491 shares outstanding, redemption value $1,449,100
net of related commissions 1,303,168 -
- -----------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK 6,762,218 5,459,050
- -----------------------------------------------------------------------------------------------------------------------
STOCKHOLDERS' EQUITY (Notes 10 and 11)
Common stock, $.001 par value; authorized 50,000,000 shares;
11,459,279 and 10,560,605 shares issued, respectively 11,460 10,561
Additional paid-in capital 42,237,276 39,242,555
Accumulated deficit (27,776,726) (24,115,382)
Accumulated other comprehensive loss (115,500) -
Treasury Stock, at cost, 14,500 shares (145,887) (145,887)
- -----------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY 14,210,623 14,991,847
- -----------------------------------------------------------------------------------------------------------------------
$ 32,584,391 $ 32,128,245
=======================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-5
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF LOSS
================================================================================
YEARS ENDED DECEMBER 31, 2002 2001 2000
- -------------------------------------------------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
Oil and gas revenues $ 5,437,723 $ 6,656,758 $ 5,241,076
Pipeline transportation revenues 259,677 296,331 -
Interest Income 3,078 43,597 45,905
- -------------------------------------------------------------------------------------------------------------------------
Total revenues and other income 5,700,478 6,996,686 5,286,981
- -------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Production costs and taxes 3,094,731 2,951,746 2,614,414
Depreciation, depletion and amortization
(Notes 4, 5 and 6) 2,413,597 1,849,963 371,249
General and administrative 1,868,141 2,957,871 2,602,311
Interest expense 578,039 850,965 415,376
Public relations 193,229 293,448 106,195
Professional fees 707,296 355,480 719,320
- -------------------------------------------------------------------------------------------------------------------------
Total costs and expenses 8,855,033 9,259,473 6,828,865
- -------------------------------------------------------------------------------------------------------------------------
NET LOSS (3,154,555) (2,262,787) (1,541,884)
Dividends on preferred stock (506,789) (391,183) (257,557)
- -------------------------------------------------------------------------------------------------------------------------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS $(3,661,344) $(2,653,970) $(1,799,441)
- -------------------------------------------------------------------------------------------------------------------------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS PER SHARE
Basic and diluted $ (0.33) $ (0.26) $ (0.19)
- -------------------------------------------------------------------------------------------------------------------------
Weighted average shares outstanding 11,062,436 10,235,253 9,253,622
========================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-6
================================================================================
COMMON STOCK ADDITIONAL
------------------------------- PAID-IN
SHARE AMOUNT CAPITAL
- --------------------------------------------------------------------------------------------------------------------------
BALANCE, January 1, 2000 8,532,882 $ 8,533 $20,732,759
Net loss - - -
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 - - -
- --------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 2000 9,295,558 9,296 25,941,709
Net loss - - -
Common stock issued with 5% stock dividend (Note 10) 498,016 498 6,374,111
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
Common stock issued for services 10,000 10 69,990
Common stock issued in private placements, net 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 - - -
- --------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 2001 10,560,605 10,561 39,242,555
Net loss - - -
Comprehensive loss
Net loss - - -
Other comprehensive loss - - -
Comprehensive loss - - -
Common stock issued in private placements, net of 2,676,150
related expenses 850,000 850
Common stock issued on conversion of debt 20,592 20 119,980
Common stock issued in purchase of equipment 19,582 20 149,980
Common stock issued for services 8,500 9 48,611
Dividends on convertible redeemable preferred stock - - -
- --------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 2002 11,459,279 $11,460 $42,237,276
==========================================================================================================================
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
================================================================================
ACCUMULATED OTHER TREASURY STOCK
COMPREHENSIVE ACCUMULATED COMPREHENSIVE -------------------------------
INCOME (LOSS) DEFICIT LOSS SHARES AMOUNT TOTAL
- -------------------------------------------------------------------------------------------------------------------
$ - $(13,287,362) - $ - $ 7,453,930
- (1,541,884) - - (1,541,884)
- - - - 449,994
- - - - 180,013
- - - - 50,000
- - - - 242,000
- - - - 4,245,708
- - - - 41,998
- (257,557) - - (257,557)
- -------------------------------------------------------------------------------------------------------------------
- (15,086,803) - - 10,864,202
(2,262,787) - - (2,262,787)
- (6,374,609) - - -
- - - - 523,250
- - - - 2,341,000
- - - - 71,001
- - - 70,000
- - - - 3,899,998
- - - - 22,253
- - 14,500 (145,887) (145,887)
- (391,183) - - (391,183)
- -------------------------------------------------------------------------------------------------------------------
(24,115,382) 14,500 (145,887) 14,991,847
(3,154,555) - - (3,154,555)
- - (3,154,555) - - -
(115,500) - (115,500) - - (115,500)
----------------
- - (3,270,055) - - -
- - - 2,677,000
- - - 120,000
- - - 150,000
- - - 48,620
- - - - -
- (506,789) - - (506,789)
- -------------------------------------------------------------------------------------------------------------------
$(115,500) $(27,776,726) 14,500 $(145,887) $14,210,623
===================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-7
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
================================================================================
YEARS ENDED DECEMBER 31, 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss $(3,154,555) $(2,262,787) $(1,541,884)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depreciation, depletion and amortization 2,413,597 1,849,963 371,249
Compensation and services paid in stock options, stock
warrants, and common stock 48,620 92,253 284,000
Gain on sale of equipment - (132,943) -
Changes in assets and liabilities:
Accounts receivable (69,192) 3,814 (301,421)
Participant receivables 13,492 - -
Inventory (103,384) 91,981 8,408
Other assets 58,000 - -
Accounts payable - trade 188,597 191,702 364,553
Accrued interest payable 7,003 (2,519) 135,435
Other accrued liabilities 31,805 (52,640) (140,955)
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used in operating activities (566,017) (221,176) (820,615)
- ---------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to other property and equipment (214,897) (285,722) (1,276,783)
Net additions to oil and gas properties (1,982,529) (4,821,883) (1,456,996)
Additions to pipeline facilities (841,750) (4,213,095) (6,834,196)
Decrease (increase) in restricted cash 120,872 (120,872) 625,000
Other 28,367 32,888 6,112
- ---------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (2,889,937) (9,408,684) (8,936,863)
- ---------------------------------------------------------------------------------------------------------------------------
F-8
TENGASCO, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
================================================================================
YEARS ENDED DECEMBER 31, 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from exercise of options $ - $ 2,341,000 $ 180,013
Proceeds from borrowings 2,063,139 10,442,068 6,493,563
Repayments of borrowings (2,378,273) (8,833,325) (1,720,856)
Net proceeds from issuance of common stock 2,677,000 3,900,000 4,245,700
Proceeds from private placements of convertible
redeemable preferred stock, net 1,303,168 1,591,150 2,000,000
Dividends on convertible redeemable preferred stock (364,858) (357,503) (257,557)
Purchase of treasury stock - (145,887) -
Payment of loan fees (53,543) (518,167) -
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 3,246,633 8,419,336 10,940,863
- --------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (209,321) (1,210,524) 1,183,385
CASH AND CASH EQUIVALENTS, beginning of year 393,451 1,603,975 420,590
- --------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, end of year $ 184,130 $ 393,451 $ 1,603,975
==========================================================================================================================
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 2002, 2001 and 2000, respectively,
the Company issued common stock on
conversion of debt. $ 120,000 $ 523,250 $ 450,000
During 2002, 2001 and 2000, respectively, the
Company issued common stock and stock options
for services received and charitable contributions
made. $ 48,620 $ 92,253 $ 284,000
During 2001, the Company sold equipment
for equity investments. $ - $ 150,000 $ -
During 2002, the Company purchased equipment
by issuing common stock $ 150,000 $ - $ -
==========================================================================================================================
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
F-9
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
1. GOING CONCERN The accompanying consolidated financial
UNCERTAINTY statements have been prepared in conformity
with accounting principles generally accepted
in the United States of America, which
contemplate continuation of the Company as a
going concern and assume realization of assets
and the satisfaction of liabilities in the
normal course of business. The Company
continues to be in the early stages of its oil
and gas related operating history as it
endeavors to expand its operations through the
continuation of its drilling program in the
Tennessee Swan Creek Field. Accordingly, the
Company has incurred continuous losses through
these operating stages and has an accumulated
deficit of $27,776,726 and a working capital
deficit of $7,998,835 as of December 31, 2002.
During 2002, the Company was informed by its
primary lender that the entire amount of its
outstanding credit facility was immediately due
and payable, as provided for in the Credit
Agreement (see Note 7). 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.
2. SUMMARY OF ORGANIZATION
SIGNIFICANT ACCOUNTING
POLICIES Tengasco, Inc. (the "Company"), a publicly held
corporation, was organized under the laws of
the State of Utah on April 18, 1916, as Gold
Deposit Mining and Milling Company. The Company
subsequently changed its name to Onasco
Companies, Inc.
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.
F-10
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The Company changed its domicile from the State
of Utah to the State of Tennessee on May 5,
1995 and its name was changed from "Onasco
Companies, Inc." to "Tengasco, Inc."
The Company's principal business consists of
oil and gas exploration, production and related
property management in the Appalachian region
of eastern Tennessee and in the state of
Kansas. The Company's corporate offices are in
Knoxville, Tennessee. The Company operates as
one reportable business segment, based on the
similarity of activities.
During 1996, the Company formed Tengasco
Pipeline Corporation ("TPC"), a wholly-owned
subsidiary, to manage the construction and
operation of a 65-mile gas pipeline as well as
other pipelines planned for the future. During
2001, TPC began transmission of natural gas
through its pipeline to customers of Tengasco.
BASIS OF PRESENTATION
The consolidated financial statements include
the accounts of the Company, Tengasco Pipeline
Corporation and Tennessee Land and Mineral,
Inc. All significant intercompany balances and
transactions have been eliminated.
USE OF ESTIMATES
The accompanying financial statements are
prepared in conformity with accounting
principles generally accepted in the United
States of America which require management to
make estimates and assumptions that affect the
reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities
at the date of the financial statements and the
reported amounts of revenues and expenses
during the reporting period. The actual results
could differ from those estimates.
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.
F-11
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
INVESTMENT SECURITIES
Investment securities available for sale are
reported at fair value, with unrealized gains
and losses, when material, reported as a
separate component of stockholders' equity, net
of the related tax effect. Other comprehensive
losses of $115,500 were recorded during the
year ended December 31, 2002 resulting from a
decrease in the fair value of the securities.
INVENTORY
Inventory consists primarily of crude oil in
tanks and is carried at market value.
OIL AND GAS PROPERTIES
The Company follows the full cost method of
accounting for oil and gas property
acquisition, exploration and development
activities. Under this method, all productive
and nonproductive costs incurred in connection
with the acquisition of, exploration for and
development of oil and gas reserves for each
cost center are capitalized. Capitalized costs
include lease acquisitions, geological and
geophysical work, delay rentals and the costs
of drilling, completing 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. These
reserves were estimated by Ryder Scott Company,
Petroleum Consultants in 2000, 2001 and 2002.
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
F-12
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
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
2002, 2001 or 2000.
PIPELINE FACILITIES
Phase I of the pipeline was completed during
1999. Phase II of the pipeline was completed on
March 8, 2001. Both phases of the pipeline were
placed into service upon completion of Phase
II. The pipeline is being depreciated over its
estimated useful life of 30 years, beginning at
the time it was placed in service.
OTHER PROPERTY AND EQUIPMENT
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.
F-13
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
STOCK-BASED COMPENSATION
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:
2002 2001 2000
-----------------------------------------------------------------------------------------------
Net loss attributable to common
shareholders
As reported $(3,661,344) $(2,653,970) $(1,799,441)
Stock based compensation (77,821) (257,328) 2,253,011
----------- ----------- -----------
Pro forma $(3,739,165) (2,911,298) (4,052,452)
-----------------------------------------------------------------------------------------------
Basic and diluted loss per share
As reported $ (0.33) $ (0.26) $ (0.19)
Pro forma (0.34) (0.28) (0.44)
-----------------------------------------------------------------------------------------------
ACCOUNTS RECEIVABLE
Senior management reviews accounts receivable
on a monthly basis to determine if any
receivables will potentially be uncollectible.
We include any accounts receivable balances
that are determined to be uncollectible, along
with a general reserve, in our overall
allowance for doubtful accounts. After all
attempts to collect a receivable have failed,
the receivable is written off against the
allowance. Based on the information available
to us, we believe no allowance for doubtful
accounts as of December 31, 2002 is necessary.
However, actual write-offs may occur.
INCOME TAXES
The Company accounts for income taxes using the
"asset and liability method." Accordingly,
deferred tax liabilities and assets are
determined based on the temporary differences
between the financial reporting and tax bases
of assets and liabilities, using enacted tax
rates in effect for the year in which the
differences are expected to reverse. Deferred
tax assets arise primarily from net operating
loss carryforwards. Management evaluates the
likelihood of realization of such assets at
year end reserving any such amounts not likely
to be
F-14
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
recovered in future periods.
CONCENTRATION OF CREDIT RISK
Financial instruments which potentially subject
the Company to concentrations of credit risk
consist principally of cash and accounts
receivable. At times, such cash in banks is in
excess of the FDIC insurance limit.
The Company's primary business activities
include oil and gas sales to several customers
in the states of Tennessee and Kansas. The
related trade receivables subject the Company
to a concentration of credit risk within the
oil and gas industry.
The Company has entered into contracts to
supply two manufacturers with natural gas from
the Swan Creek field through the Company's
pipeline. These customers are the Company's
primary customers of natural gas sales.
Additionally, the Company sells a majority of
its crude oil primarily to two customers, one
each in Tennessee and Kansas. Although
management believes that customers could be
replaced in the ordinary course of business, if
the present customers were to discontinue
business with the Company, it could have a
significant adverse effect on the Company's
projected results of operations.
LOSS PER COMMON SHARE
Basic loss per share is computed by dividing
loss available to common shareholders by the
weighted average number of shares outstanding
during each year. Shares issued during the year
are weighted for the portion of the year that
they were outstanding. Diluted loss per share
does not differ from basic loss per share since
the effect of all common stock equivalents is
anti-dilutive. Basic and diluted loss per share
are based upon 11,062,436 shares for the year
ended December 31, 2002, 10,235,253 shares for
the year ended December 31, 2001, and 9,253,622
shares for the year ended December 31, 2000.
Dilated loss per share does not consider
approximately 1,473,000, 943,000 and 1,001,000
potential weighted average common shares for
2002, 2001 and 2000 related primarily to common
stock options and convertible preferred stock
and debt. These shares were not included in the
computation of the diluted loss per share
amount because the Company was in a net loss
position and, thus, any potential common shares
were anti-dilutive. All share and per share
amounts have been adjusted to reflect the 5%
stock dividend.
F-15
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
FAIR VALUES OF FINANCIAL INSTRUMENTS
Fair values of cash and cash equivalents,
investments and short-term debt approximate
their carrying values due to the short period
of time to maturity. Fair values of long-term
debt are based on quoted market prices or
pricing models using current market rates,
which approximate carrying values.
RECENT ACCOUNTING PRONOUNCEMENTS
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 was 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
did not have an effect on the Company's
financial position or results of operations.
In 2001, the Financial Accounting Standards
Board (FASB) issued SFAS No. 143, "Accounting
for Asset Retirement Obligations." SFAS No. 143
addresses financial accounting and reporting
for obligations associated with the retirement
of tangible long-lived assets and the
associated asset retirement costs. This
statement requires companies to record the
present value of obligations associated with
the retirement of tangible long-lived assets in
the period in which it is incurred. The
liability is capitalized as part of the related
long-lived asset's carrying amount. Over time,
accretion of the liability is recognized as an
operating expense and the capitalized cost is
depreciated over the expected useful life of
the related asset. The Company's asset
retirement obligations relate primarily to the
plugging dismantlement, removal, site
reclamation and similar activities of its oil
and gas properties. Prior to adoption of this
statement, such obligations were accrued
ratably over the productive
F-16
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
lives of the assets through its depreciation,
depletion and amortization for oil and gas
properties without recording a separate
liability for such amounts. The Company plans
to adopt SFAS 143 beginning on January 1,
2003; however, the effect of adoption of this
statement on future results of operations or
financial position has not yet been determined
by management.
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, 2003.
Management does not expect that adoption of
this standard will have a material impact on
the Company's financial position or results of
operations.
The FASB issued Statement No. 145, Rescission
of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical
Corrections, on April 30, 2002. SFAS No. 145
will be effective for fiscal years beginning
after May 15, 2002. This statement rescinds
SFAS No. 4, Reporting Gains and Losses From
Extinguishment of Debt, and requires that all
gains and losses from extinguishment of debt
should be classified as extraordinary items
only if they meet the criteria in APB No. 30.
Applying APB No. 30 will distinguish
transactions that are part of an entity's
recurring operations from those that are
unusual or infrequent or that meet the criteria
for classification as an extraordinary item.
Any gain or loss on extinguishment of debt that
was classified, as an extraordinary item in
prior periods presented that does not meet the
criteria in APB No. 30 for classification as an
extraordinary item must be reclassified. There
is no current impact of adoption on the
Company's financial position or results of
operations.
The FASB issued Statement No. 146, Accounting
for Costs Associated with Exit or Disposal
Activities, in June 2002. SFAS No. 146
addresses financial accounting and reporting
for costs associated with exit or disposal
activities and nullifies Emerging Issues Task
Force Issue No. 94-3, Liability Recognition for
Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain
Costs incurred in a Restructuring). SFAS No.
146 applies to costs incurred in an "exit
activity", which includes, but is not limited
to, a restructuring, or a "disposal activity"
covered by SFAS No. 144.
F-17
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
SFAS No. 146 requires that a liability for a
cost associated with an exit or disposal
activity be recognized when the liability is
incurred. Previously, under Issue 94-3, a
liability for an exit cost was recognized at
the date of an entity's commitment to an exit
plan. Statement No. 146 also establishes that
fair value is the objective for initial
measurement of the liability. The provisions of
SFAS No. 146 are effective for exit or disposal
activities that are initiated after December
31, 2002. Management does not expect that
adoption of this standard will have a material
effect on the Company's financial position or
results of operations.
In November 2002, the FASB issued
Interpretation No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness
to Others, an interpretation of FASB Statements
No. 5, 57 and 107 and a rescission of FASB
Interpretation No. 34. This Interpretation
elaborates on the disclosures to be made by a
guarantor in its interim and annual financial
statements about its obligations under
guarantees issued. The Interpretation also
clarifies that a guarantor is required to
recognize, at inception of a guarantee, a
liability for the fair value of the obligation
undertaken. The initial recognition and
measurement provisions of the Interpretation
are applicable to guarantees issued or modified
after December 31, 2002. The Company has not
guaranteed the debts of others, therefore, this
interpretation is not expected to have a
material effect on Tengasco's financial
statements.
In December 2002, the FASB issued SFAS No. 148,
Accounting for Stock-Based Compensation -
Transition and Disclosure, an amendment of FASB
Statement No. 123. This Statement amends FASB
Statement No. 123, Accounting for Stock-Based
Compensation, to provide alternative methods of
transition for a voluntary change to the fair
value method of accounting for stock-based
employee compensation. In addition, this
Statement amends the disclosure requirements of
Statement No. 123 to require prominent
disclosures in both annual and interim
financial statements. Management has adopted
certain of the disclosure modifications are
required for fiscal years ending after
December 15, 2002 and are included in the notes
to the accompanying consolidated financial
statements.
F-18
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In January 2003, the FASB issued Interpretation
No. 46, Consolidation of Variable Interest
Entities, an Interpretation of Accounting
Research Bulletin No. 51. Interpretation No. 46
requires a company to consolidate a variable
interest entity if the company has a variable
interest (or combination of variable interests)
that will absorb a majority of the entity's
expected losses if they occur, receive a
majority of the entity's expected residual
returns if they occur, or both. A direct or
indirect ability to make decisions that
significantly affect the results of the
activities of a variable interest entity is a
strong indication that a company has one or
both of the characteristics that would require
consolidation of the variable interest entity.
Interpretation No. 46 also requires additional
disclosures regarding variable interest
entities. The new interpretation is effective
immediately for variable interest entities
created after January 31, 2003, and is
effective in the first interim or annual period
beginning after June 15, 2003, for variable
interest entities in which a company holds a
variable interest that it acquired before
February 1, 2003. Management does not expect
that adoption of this interpretation will have
a material effect on the Company's financial
position or results of operations.
RECLASSIFICATIONS
Certain prior year amounts have been
reclassified to conform with current year
presentation.
3. RELATED PARTY During 2002 the Company received debt financing
TRANSACTIONS from a director totaling $750,000 to fund
operating cash flow needs and to finance
continued development of the Swan Creek field.
Interest incurred on this debt was
approximately $15,000 for the year ended
December 31, 2002. See Note 7.
During 2002, the Company borrowed $110,000 from
a former director. The advance was non-interest
bearing and was repaid in July 2002.
During 2001, the Company repaid all principal
and interest due to related parties, using the
proceeds from the line of credit with Bank One.
Interest incurred to related parties was
approximately $15,000, $546,000 and $135,000
for the years ended December 31, 2002, 2001 and
2000, respectively.
F-19
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
During 2001, the Company converted debt of
$200,000 payable to a director into 42,017
shares of common stock.
During 2000, the Company paid approximately
$270,000 in consulting fees and commissions on
equity transactions to a member of the Board of
Directors.
4. OIL AND GAS The following table sets forth information
PROPERTIES concerning the Company's oil and gas
properties:
DECEMBER 31, 2002 2001
--------------------------------------------------------------------------
Oil and gas properties, at cost $17,099,753 $15,117,224
Accumulation depreciation,
depletion and amortization (3,235,432) (1,847,294)
--------------------------------------------------------------------------
Oil and gas properties, net $13,864,321 $13,269,930
==========================================================================
During the years ended December 31, 2002, 2001
and 2000, the Company recorded depletion
expense of approximately $1,388,000, $1,342,000
and $197,000, respectively.
5. PIPELINE FACILITIES In 1996, the Company began construction of a
65-mile gas pipeline (1) connecting the Swan
Creek development project to a gas purchaser
and (2) enabling the Company to develop gas
distribution business opportunities in the
future. Phase I, a 30-mile portion of the
pipeline, was completed in 1998. Phase II of
the pipeline, the remaining 35 miles, was
completed in March 2001. The estimated useful
life of the pipeline for depreciation purposes
is 30 years. The Company recorded approximately
$220,000 and $509,000, respectively in
depreciation expense related to the pipeline
for the years ended December 31, 2002 and 2001.
No depreciation expense was recorded in 2000 as
the pipeline was not yet complete.
F-20
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In January 1997, the Company entered
into an agreement with the Tennessee
Valley Authority ("TVA") whereby the TVA
allows the Company to bury the pipeline
within the TVA's transmission line
rights-of-way. In return for this right,
the Company paid $35,000 and agreed to
annual payments of approximately $6,200
for 20 years. This agreement expires in
2017 at which time the parties may renew
the agreement for another 20 year term
in consideration of similar
inflation-adjusted payment terms.
6. OTHER PROPERTY Other property and equipment consisted of the
AND EQUIPMENT following:
DECEMBER 31, 2002 2001
-----------------------------------------------------------------------------
Machinery and equipment $1,887,190 $1,737,189
Vehicles 675,411 610,510
Other 63,734 63,739
-----------------------------------------------------------------------------
2,626,335 2,411,438
Less accumulated depreciation (940,385) (731,334)
-----------------------------------------------------------------------------
Other property and equipment - net $1,685,950 $1,680,104
-----------------------------------------------------------------------------
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, 2002 2001
-----------------------------------------------------------------------------------
Revolving line of credit with a bank, due
November 2004. The loan agreement provides
for increases or decreases to the borrowing
base as changes in proved oil and gas
reserves or other production levels arise.
Borrowings bear interest at the bank's prime
rate plus 0.25% (4.5% at December 31, 2002).
Collateralized by the oil and gas properties
and the related operations and revenues. 7,501,777 $9,101,777
Unsecured note payable to an institution, with
$65,000 principal payments due quarterly
beginning January 1, 2000; remaining balance
due October 2004; with interest payable monthly
at 8% per annum. Note is convertible into
common stock of the Company at a rate of $6.25
per share of common stock. 480,000 720,000
Convertible notes payable to five individuals;
due January 2004, with interest payable
quarterly at 8% per annum. Notes are
convertible into common stock of the Company at
a rate of $3.00 per share of common stock. 650,000 -
Note payable to a financial institution, with
$1,773 principal payments due monthly beginning
January 7, 2002 through December 7, 2006.
Interest is payable monthly commencing on
January 7, 2002 at 7.5% per annum. Note is
guaranteed by a major shareholder and is
collateralized by certain assets of the
Company. 73,335 87,500
-----------------------------------------------------------------------------------
Balance carried forward 8,705,112 9,909,277
-----------------------------------------------------------------------------------
F-22
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
DECEMBER 31, 2002 2001
-----------------------------------------------------------------------------------
Balance brought forward 8,705,112 9,909,277
-----------------------------------------------------------------------------------
Installment notes bearing interest at the rate
of 3.9% to 11.95% per annum collateralized by
vehicles and equipment with monthly payments
including interest of approximately $10,000 due
various periods through 2006. 412,342 393,311
-----------------------------------------------------------------------------------
Total long term debt 9,117,454 10,302,588
Less current maturities (7,861,245) (6,399,831)
-----------------------------------------------------------------------------------
Long term debt less current maturities $ 1,256,209 $ 3,902,757
-----------------------------------------------------------------------------------
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 on the
revolving line of credit with a bank. As of
December 31, 2002, the Company is not in
compliance with all covenants. During 2002, as
a result of ongoing negotiations to refinance
or repay the debt, the bank declared all
amounts immediately due and payable. The
Company is presently paying $200,000 per month.
As a result of ongoing negotiations with Book
One, management has reclassified the loan fees
associated with this note to a current asset as
it is likely that these fees will be fully
amortized in 2003.
F-23
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
Long-term debt to related parties consisted of
the following:
DECEMBER 31, 2002 2001
-----------------------------------------------------------------------------------
Unsecured note payable to a director due
January 2004, with interest payable quarterly
at 8% per annum. Note is convertible into
common stock of the Company at a rate of $2.88
per share of common stock. $500,000 $ -
Note payable to a director due January
2004,with interest payable quarterly at 12% per
annum. Note is secured by 10% of the pipeline. 250,000 -
-----------------------------------------------------------------------------------
Total long term debt to related parties 750,000 -
Less current maturities - -
-----------------------------------------------------------------------------------
Long term debt to related parties, less
current maturities $750,000 $ -
===================================================================================
The aggregate maturities of long term debt due
to related parties and others as of December
31, 2002, are as follows:
Year Amount
-----------------------------------------------
2003 $7,861,245
2004 1,720,468
2005 101,468
2006 101,803
Thereafter 82,470
-----------------------------------------------
$9,867,454
===============================================
8. COMMITMENTS The Company is a party to lawsuits in the
AND CONTINGENCIES ordinary course of its business. While the
damages sought in some of these actions are
material, the Company does not believe that it
is probable that the outcome of any individual
action will have a material adverse effect, or
that it is likely that adverse outcomes of
individually insignificant actions will be
significant enough, in number or magnitude, to
have a material adverse effect in the aggregate
on its financial statements.
F-24
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
In the ordinary course of business the Company
has entered into various equipment and office
leases which have remaining terms ranging from
one to four years. Approximate future minimum
lease payments to be made under noncancellable
operating leases are as follows:
Year Amount
-----------------------------------------------
2003 $ 60,158
2004 59,210
2005 56,970
2006 500
-----------------------------------------------
$176,838
===============================================
Office rent expense was approximately $84,000,
$91,000 and $86,000 for each of the three years
ended December 31, 2002, respectively.
9. CUMULATIVE
CONVERTIBLE Shares of both Series A and B of Preferred
REDEEMABLE Stock are or will be immediately convertible
PREFERRED STOCK 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.
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.
F-25
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The Company failed to pay the 3rd and 4th
quarterly dividend payments of the Series A
preferred stock during 2002. As a result, in
February 2003, the Series A shareholders
exercised their rights to place four new
members on the Board of Directors.
The Company may redeem both of the Series A and
B Preferred Shares upon payment of $100 per
share plus any accrued and unpaid dividends.
Further, with respect to the Series A Preferred
Stock, commencing on October 1, 2003 and at
each quarterly date thereafter while the Series
A Preferred Stock is outstanding, the Company
is required to redeem one-twentieth of the
maximum number of Series A Preferred Stock
outstanding. With respect to the Series B
Preferred Stock, on the fifth anniversary after
issuance (March 2005), the Company is required
to redeem all outstanding Series B Preferred
Stock.
During 2002, the Board of Directors authorized
the sale of up to 50,000 shares of Series C
Preferred Stock at $100 per share. The Company
issued 14,491 shares, resulting in net proceeds
after commissions of $1,303,168. The Series C
Preferred Stock accrues a 6% cumulative
dividend on the outstanding balance, payable
quarterly. These dividends are subordinate to
the dividends payable to the Series A and
Series B Preferred Stock holders. This stock is
convertible into the Company's common stock at
the average stock trading price 30 days prior
to the closing of the sales of all the Series C
Preferred Stock being offered or $5.00 per
share, whichever is greater. The Company is
required to redeem any remaining Series C
Preferred Stock and any accrued and unpaid
dividends in July 2006.
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.
F-26
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
11. STOCK OPTIONS In October 2000, the Company approved a Stock
Incentive Plan. The Plan is effective for a
ten-year period commencing on October 25, 2000
and ending on October 24, 2010. The aggregate
number of shares of Common Stock as to which
options and Stock Appreciation Rights may be
granted to Employees under the plan shall not
exceed 1,000,000. Options are not transferable,
fully vest after two years of employment with
the Company, are exercisable for 3 months after
voluntary resignation from the Company, and
terminate immediately upon involuntary
termination from the Company. The purchase
price of shares subject to this Nonqualified
Stock Option Plan shall be determined at the
time the options are granted, but are not
permitted to be less than 85% of the Fair
Market Value of such shares on the date of
grant. Furthermore, an employee in the plan may
not, immediately prior to the grant of an
Incentive Stock Option hereunder, own stock in
the Company representing more than ten percent
of the total voting power of all classes of
stock of the Company unless the per share
option price specified by the Board for the
Incentive Stock Options granted such 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 2002, 2001 and 2000 is
summarized below:
2002 2001 2000
------------------------- ------------------------ ------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
- ----------------------------------------------------------------------------------------------------------------------
OUTSTANDING,
beginning
of year 516,028 $9.23 1,017,450 $ 8.54 530,250 $6.91
Granted 160,742 2.86 78,750 12.39 855,451 8.69
Exercised - - (256,772) 8.69 (21,751) 8.69
Expired/canceled - - (323,400) 7.85 (346,500) 6.91
--------- ---------- ----------
OUTSTANDING,
end of year 676,770 7.71 516,028 9.23 1,017,450 8.54
- ----------------------------------------------------------------------------------------------------------------------
EXERCISABLE,
end of year 676,770 $7.71 474,889 $ 9.21 930,258 $8.49
======================================================================================================================
F-27
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The share information disclosed above has been
adjusted to reflect the 5% stock dividend
declared during 2001. See Note 10.
The following table summarizes information
about stock options outstanding at December 31,
2002:
OPTIONS OPTIONS
OUTSTANDING EXERCISABLE
------------------------------------------ ---------------
WEIGHTED
WEIGHTED AVERAGE
AVERAGE REMAINING
EXERCISE CONTRACTUAL
PRICE SHARES LIFE (YEARS) SHARES
========================================================== ---------------
$ 2.86 160,742 2.67 160,742
$ 8.69 437,278 0.85 437,278
$ 14.44 21,000 1.13 21,000
$ 11.05 47,250 1.30 47,250
$ 12.70 10,500 1.71 10,500
------------ ---------------
Total $ 7.71 676,770 676,770
============================================================================
The weighted average fair value per share of
options granted during 2002, 2001 and 2000 is
$1.45, $3.62, and $3.41 respectively,
calculated using the Black-Scholes
Option-Pricing model.
No compensation expense related to stock
options was incurred in 2002, 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.
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 2002, 2001 and
2000: Expected volatility of 74.2% for 2002,
50% for 2001 and 50% for 2000; a risk free
interest rate of 3.67% in 2002, 3.67% in 2001
and 5.86% in 2000; and an expected option life
of 3 years for 2002, 2001 and 2000.
F-28
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
12. INCOME TAXES The Company has no taxable income during the
three year period ended December 31, 2002.
A reconciliation of the statutory U.S. Federal
income tax and the income tax provision
included in the accompanying consolidated
statements of loss is as follows:
DECEMBER 31, 2002 2001 2000
------------------------------------------------------------------------------------------------
Statutory rate 34% 34% 34%
Tax benefit at statutory rate $(1,073,000) $ (769,000) $(452,500)
State income tax benefit (189,000) (136,000) (75,500)
Other - - 24,000
Increase in deferred tax asset
valuation allowance 1,262,000 905,000 504,000
------------------------------------------------------------------------------------------------
Total income tax provision $ - $ - $ -
================================================================================================
DECEMBER 31, 2002 2001 2000
-------------------------------------------------------------------------------------------------
Net operating loss carryforward $ 7,139,000 $ 5,877,000 $ 4,972,000
Capital loss carryforward 263,000 263,000 263,000
-------------------------------------------------------------------------------------------------
7,402,000 6,140,000 5,235,000
Valuation allowance (7,402,000) (6,140,000) (5,235,000)
-------------------------------------------------------------------------------------------------
Net deferred taxes $ - $ - $ -
================================================================================================
The Company recorded a valuation allowance at
December 31, 2002, 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. Potential
future reversal of the portion of the valuation
allowance relative to deferred tax asset
resulting from the exercise of stock options
will be recorded as additional paid in capital
realized
As of December 31, 2002, the Company had net
operating loss carryforwards of approximately
$18,217,000, which will expire between 2010 and
2022, if not utilized.
F-29
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
13. SUPPLEMENTAL CASH The Company paid approximately $571,000,
FLOW INFORMATION $853,500 and $544,000 for interest in 2002,
2001 and 2000, respectively. The Company
capitalized approximately $148,000 and $128,000
of this amount in 2001 and 2000, respectively.
No interest was capitalized during 2002. The
Company paid no income taxes in 2002, 2001 and
2000.
F-30
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
14. QUARTERLY DATA AND The following table sets forth, for the fiscal
SHARE INFORMATION periods indicated, selected consolidated
(UNAUDITED) financial data.
FISCAL YEAR ENDED 2002
- ------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
- ------------------------------------------------------------------------------------------------------------------
Revenues $1,176,482 $1,297,668 $1,507,308 $1,719,020
Net loss (818,341) (858,197) (721,879) (756,138)
Net loss attributable to common
stockholders (930,799) (984,139) (856,074) (890,332)
- ------------------------------------------------------------------------------------------------------------------
Loss per common share
Basic and diluted $ (0.09) $ (0.09) $ (0.08) $ (0.07)
- ------------------------------------------------------------------------------------------------------------------
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 attributable to common
stockholders (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) attributable to common
stockholders (110,231) (451,394) 18,064 (1,255,880)
- ------------------------------------------------------------------------------------------------------------------
Earnings (loss) per common share
Basic and diluted $ (0.01) $ (0.05) $ - $ (0.13)
- ------------------------------------------------------------------------------------------------------------------
F-31
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
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 the
filing. Management has amended the September
30, 2001 SEC Form 10-Q filing during 2002.
15. SUPPLEMENTAL OIL AND Information with respect to the Company's oil
GAS INFORMATION and gas producing activities is presented in
the following tables. Estimates of reserve
quantities, as well as future production and
discounted cash flows before income taxes, were
determined by Ryder Scott Company, L.P. as of
December 31, 2002, 2001 and 2000.
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, 2002, 2001
and 2000:
2002 2001 2000
------------------------------------------------------------------------------
Property acquisition
Proved $ - $ - $ -
Unproved - - 5,702
Less - proceeds from
sales of properties (100,000) (750,000) (1,176,411)
Development costs 2,082,529 5,571,883 2,627,705
------------------------------------------------------------------------------
$ 1,982,529 $ 4,821,883 $ 1,456,996
==============================================================================
F-32
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
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, 2002 2001 2000
------------------------------------------------------------------------------
Revenues $ 5,437,723 $ 6,656,758 $ 5,241,076
Production costs and taxes (3,094,731) (2,951,746) (2,614,414)
Depreciation, depletion and
amortization (1,388,138) (1,342,000) (197,000)
------------------------------------------------------------------------------
Income from oil and gas
producing activities $ 954,854 $ 2,363,012 $ 2,429,662
------------------------------------------------------------------------------
In the presentation above, no deduction has
been made for indirect costs such as corporate
overhead or interest expense. No income taxes
are reflected above due to the Company's tax
loss carryforwards.
OIL AND GAS RESERVES (UNAUDITED)
The following table sets forth the Company's
net proved oil and gas reserves at December 31,
2002, 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-33
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
OIL (BBLS) GAS (MCF)
-----------------------------------------------------------------------------
Proved reserves:
Balance, January 1, 2000 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)
-----------------------------------------------------------------------------
Balance, December 31, 2001 1,056,675 25,880,202
Discoveries and extensions 34,968 937,000
Revisions of previous estimates 542,229 786,430
Production (157,973) (1,004,899)
-----------------------------------------------------------------------------
Proved reserves at, December 31, 2002 1,475,899 26,598,733
=============================================================================
Proved developed producing
reserves at, December 31, 2002 1,108,293 6,592,711
=============================================================================
Proved developed producing
reserves at, December 31, 2001 767,126 7,157,183
=============================================================================
Proved developed producing
reserves at, December 31, 2000 1,553,759 2,888,769
=============================================================================
Of the Company's total proved reserves as of
December 31, 2002 and 2001 and 2000,
approximately 37%, 36% and 21%, respectively,
were classified as proved developed producing,
19%, 26% and 34%, respectively, were classified
as proved developed non-producing and 44%, 37%
and 45%, respectively, were classified as
proved undeveloped. All of the Company's
reserves are located in the continental United
States.
F-34
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, 2002 2001 2000
-----------------------------------------------------------------------------
Future cash inflows $152,180 $ 78,296 $ 505,733
Future production
costs and taxes (41,870) (26,083) (41,689)
Future development costs (11,348) (6,384) (8,225)
Future income tax expenses - - (122,881)
-----------------------------------------------------------------------------
Net future cash flows 98,962 45,829 332,938
Discount at 10% for
timing of cash flows (52,314) (24,095) (97,195)
-----------------------------------------------------------------------------
Discounted future net
cash flows from
proved reserves $ 46,648 $ 21,734 $ 235,743
-----------------------------------------------------------------------------
F-35
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
The following unaudited table sets forth the
changes in the standardized measure of
discounted future net cash flows from proved
reserves during 2002, 2001 and 2000:
AMOUNTS IN THOUSANDS
--------------------------------------------
2002 2001 2000
-----------------------------------------------------------------------------
BALANCE, beginning of year $ 21,734 $ 235,743 $ 100,882
Sales, net of production costs
and taxes (2,343) (3,705) (2,627)
Discoveries and extensions 1,686 4,167 1,778
Changes in prices and
production costs 20,586 (299,527) 360,082
Revisions of quantity estimates 6,120 (33,449) (186,289)
Development costs incurred - 1,236
Interest factor - accretion
of discount 2,173 32,198 13,355
Net change in income taxes - 86,237 (53,572)
Changes in future development
costs (4,860) 2,666 (3,237)
Changes in production rates
and other 1,552 (2,596) 4,135
-----------------------------------------------------------------------------
BALANCE, end of year $ 46,648 $ 21,734 $ 235,743
-----------------------------------------------------------------------------
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, 2002, 2001
and 2000 were $27.25, $17.03 and $25.62 per
barrel of oil and $4.01, $2.33 and $9.66 per
MCF of gas, respectively. No deduction has been
made for depreciation, depletion or any
indirect costs such as general corporate
overhead or interest expense.
Operating costs and production taxes are
estimated based on current costs with respect
to producing gas properties. Future development
costs are based on the best estimate of such
costs assuming current economic and operating
conditions. The estimates of reserve values
include estimated future development costs that
the company does not currently have the ability
to fund. If the company is unable to obtain
additional funds, it may not be able to develop
its oil and natural gas properties as estimated
in its December 31, 2002 reserve report.
F-36
TENGASCO, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
================================================================================
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