# UNITED STATESSecurities 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, 2005 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

|Tennessee                                                     |  | 87-0267438                          
|------------------------------------------------------------- |  | ------------------------------------
|(State
or other jurisdiction ofincorporation or organization) |  | (I.R.S. Employer
Identification No.)
|                                                              |  |                                     
|                                                              |  |                                     

# TENGASCO, INC.

# (Name of registrant as
specified in its charter)

# 10215 Technology Drive
N.W., Knoxville, Tennessee 37932-3379

# (Address of Principal
Executive Offices) (Zip Code)

# Registrants
telephone number, including area code: (865) 675-1554.

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 check mark 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 for
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 check mark if disclosure of delinquent filers in response to Item 405 of Regulation SK
is not contained herein, and will not be contained, to the best of 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.[ ]

Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large
accelerated filer in Rule 12b-2 of the Exchange Act. Large Accelerated Filer [ ]
Accelerated Filer [ ] Non-accelerated

Filer |X|

Indicate
by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange 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 fiscal quarter (June 30, 2005
closing price $0.25): $7,488,456

State
the number of shares outstanding of the registrants $.001 par value common stock as
of the close of business on the latest practicable date (March 1, 2006): 58,605,698

# Documents Incorporated
By Reference

The
information required by Part III of the Form 10-K, to the extent not set forth herein, is
incorporated herein by reference from the registrants definitive proxy statement for
the Annual Meeting of Shareholders to be held on April 24, 2006, to be filed with the
Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days
after the close of the registrants fiscal year



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Table of Contents

|PART I   |  |                                                                                                                                   |   
|-------- |  | --------------------------------------------------------------------------------------------------------------------------------- | --
|         |  | Item 1.     Business                                                                                                              | 1 
|         |  | Item 1A.     Risk Factors                                                                                                         | 16
|         |  | Item 1B.     Unresolved Staff Comments                                                                                            | 20
|         |  | Item 2.     Properties                                                                                                            | 21
|         |  | Item 3.     Legal Proceedings                                                                                                     | 31
|         |  | Item 4.     Submission of Matters to a Vote of Security Holders                                                                   | 31
|PART II  |  |                                                                                                                                   |   
|         |  | Item 5.     Market for Registrant's Common Equity, Related Stockholder
         Matters and Issuer Purchases of Equity Securities | 31
|         |  | Item 6.     Selected Financial Data                                                                                               | 34
|         |  | Item 7.     Management's Discussion and Analysis of Financial Condition
         and Results of  Operation                        | 35
|         |  | Item 7A.     Quantitative and Qualitative Disclosures About Market Risk                                                           | 44
|         |  | Item 8.     Financial Statements and Supplementary Data                                                                           | 45
|         |  | Item 9.     Changes in and Disagreements With Accountants on Accounting
         and Financial Disclosure                         | 45
|         |  | Item 9A.     Controls and Procedures                                                                                              | 47
|         |  | Item 9B.     Other Information                                                                                                    | 48
|PART III |  |                                                                                                                                   |   
|         |  | Item 10.     Directors and Executive Officers of the Registrant                                                                   | 48
|         |  | Item 11.     Executive Compensation                                                                                               | 49
|         |  | Item 12.     Security Ownership of Certain Beneficial Owners and Management
         and Related Stockholder Matters              | 49
|         |  | Item 13.     Certain Relationships and Related Transactions                                                                       | 49
|         |  | Item 14.     Principal Accountant Fees and Services                                                                               | 49
|PART IV  |  |                                                                                                                                   |   
|         |  | Item 15.     Exhibits and Financial Statement Schedules                                                                           | 50
|         |  | SIGNATURES                                                                                                                        | 53

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# FORWARD LOOKING
STATEMENTS

The
information contained in this Report, in certain instances, includes forward-looking
statements within the meaning of applicable securities laws. Forward-looking statements
include statements regarding the Companys expectations,
anticipations, intentions, beliefs, or
strategies regarding the future. Forward-looking statements also include
statements regarding revenue, margins, expenses, and earnings analysis for 2005 and
thereafter; oil and gas prices; exploration activities; development expenditures; costs of
regulatory compliance; environmental matters; technological developments; future products
or product development; the Companys products and distribution development
strategies; potential acquisitions or strategic alliances; liquidity and anticipated cash
needs and availability; prospects for success of capital raising activities; prospects or
the market for or price of the Companys common stock; and control of the Company.
All forward-looking statements are based on information available to the Company as of the
date hereof, and the Company assumes no obligation to update any such forward-looking
statements. The Companys actual results could differ materially from the
forward-looking statements. Among the factors that could cause results to differ
materially are the factors discussed in Risk Factors below in Item 1A of this
Report.

Projecting
the effects of commodity prices on production and timing of development expenditures
includes many factors beyond the Companys control. The future estimates of net cash
flows from the Companys proved reserves and their present value are based upon
various assumptions about future production levels, prices, and costs that may prove to be
incorrect over time. Any significant variance from assumptions could result in the actual
future net cash flows being materially different from the estimates.

# PART IITEM 1.    BUSINESS.

# History of the Company

The
Company was initially organized under the laws of the State of Utah in 1916, under the
name Gold Deposit Mining & Milling Company. The Company subsequently
changed its name to Onasco Companies, Inc. The Company was formed for the purpose of
mining, reducing and smelting mineral ores. In 1972, the Company conveyed to an
unaffiliated entity substantially all of its assets and ceased all business operations.
From approximately 1983 to 1991, the operations of the Company were limited to seeking out
the acquisition of assets, property or businesses.

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In
1995, the Company acquired certain oil and gas leases, equipment, securities and vehicles
owned by Industrial Resources Corporation, a Kentucky corporation, changed its name from
Onasco Companies, Inc. to Tengasco, Inc., and changed the domicile of the Company from the
State of Utah to the State of Tennessee by merging into Tengasco, Inc., a Tennessee
corporation, formed by the Company solely for this purpose.

# Overview

The
Company is in the business of exploring for, producing and transporting oil and natural
gas in Kansas and Tennessee. The Company leases producing and non-producing properties
with a view toward exploration and development. Emphasis is also placed on pipeline and
other infrastructure facilities to provide transportation services. The Company utilizes
seismic technology to improve the recovery of reserves.

In
May 1995, the Companys activities in the oil and gas business commenced 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 19,521 acres. In 1998, the Company acquired from AFG Energy,
Inc. (AFG), a private company, approximately 32,000 acres of leases in the
vicinity of Hays, Kansas (the Kansas Properties). Included in that acquisition
were 273 wells, including 208 working wells, of which 149 were producing oil wells and 59
were producing gas wells, a related 50-mile pipeline and gathering system, three
compressors and 11 vehicles. The total purchase price of these assets was approximately
$5.5 million. During 2005, the Kansas Properties produced an average of approximately 669
Mcf of natural gas per day (January 2005 only) and 10,731 barrels of oil per month. The
Company sold the Kansas gas producing wells, gathering system and compressors effective
February 1, 2005 so that the Companys gas production in 2005 was limited only to the
month of January 2005.

In
Tennessee, to date, the Company has drilled primarily on a portion of its leases known as
the Swan Creek Field in Hancock County focused within what is known as the Knox Formation,
one of the geologic formations in that field. During 2005, the Company produced an average
of approximately 502 thousand cubic feet of natural gas per day and 902 barrels of oil per
month from 21 producing gas wells and 5 producing oil wells in the Swan Creek Field.

In
2001, the Companys wholly-owned subsidiary, Tengasco Pipeline Corporation
(TPC) which was formed to own and manage the construction and operation of the
Companys pipeline facilities completed a 65-mile intrastate pipeline from the Swan
Creek Field to Kingsport, Tennessee. Until the Companys pipeline was completed, the
gas wells that had been drilled in the Swan Creek Field could not be placed into actual
production and the gas transported and sold to the Companys industrial customers in
Kingsport.

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# General

# 1. The Kansas
Properties

The
Companys Kansas Properties presently include 130 producing oil wells in the vicinity
of Hays, Kansas. The Company also has 37 other wells in the same area which serve as
saltwater disposal wells which reduce operating costs by eliminating the need for
transportation out of the area of the salt water produced in the oil production process.
The aggregate production for the Kansas Properties in 2005 was 669 Mcf of gas (January
2005 only) and 353 barrels of oil per day. Revenue for the Kansas Properties was
approximately $582,534 per month in 2005 which was $431,298 net to the Companys
interest.

The
Companys gas producing properties in Kansas were physically separated from the oil
properties, and were all located in Rush County, Kansas. The Company believed that there
was a limited possibility of significant additional net revenues being obtained by the
Company from these properties. Consequently, on March 4, 2005, but effective with
production as of February 1, 2005, the Company sold fifty-three (53) producing gas wells
and saltwater disposal wells and the associated gathering system as well as the underlying
leases and rights of way constituting all of the gas wells, leases and gathering systems
in Rush County, Kansas that were purchased by the Company from AFG in 1998 to Bear
Petroleum, Inc. for $2.4 million. As a result, the Companys Kansas Properties now
consist exclusively of oil producing properties.

The
Company employs a full time geologist in Kansas to oversee operations of the Kansas
Properties.

In
2005, the Company commenced a lease acquisition program in Kansas to acquire oil and gas
leases in areas near its previous lease holdings where the Company believes there is a
likelihood of additional oil production. This newly acquired acreage is largely undrilled,
and the Company believes that current seismic exploration technology will enable the
Company to establish additional oil production by efficient location of new wells to be
drilled by the Company. The Company intends to continue to acquire additional leases in
the area of its existing wells.

In
February and March 2005, the Company began drilling the first two wells of an eight-well
drilling program in Kansas (the Eight Well Program). The Eight Well Program
was offered to the holders of the Companys Series A 8% Cumulative Convertible
Preferred Stock (Series A Shares) in exchange for their Series A Shares.
Participation in the Program was accepted by five of the thirteen Series A Shareholders
who received 6.5 units of the Drilling Program with the Company retaining the remaining
1.5 units. This resulted in the Series A Shareholders acquiring approximately an 81%
working interest in the eight wells and the Company retaining the remaining 19% working
interest. The Company, acting as operator of the Program, is charging the participants in
the Program a turnkey fee of $250,000 for each of the eight units in the
Program. In addition, under the terms of the Eight Well Program, the former Series A
shareholders participating in the Eight Well Program will receive all of the cash flow
from their 81% working interest in the eight wells until they have recovered 80% of the
face

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value of the Series A Shares they exchanged for their interests in the Eight Well
Program. At that point, for the rest of the productive lives of those eight wells, the
Company will receive 85% of the cash flow from the 81% working interest in those wells as
a management fee and the Series A shareholders will receive the remaining 15% of the cash
flow.

By
the end of 2005, the Company had drilled six of the wells in the Eight Well Program.
Although one of the wells drilled was a dry hole, the other five wells drilled so far in
the Eight Well Program have resulted in commercial production. From April 2005 when the
first well was drilled through December 31, 2005, the five producing wells in the Eight
Well Program have produced an aggregate of 14,160 barrels of oil. See, Item 2
Properties  Oil and Gas Drilling Activities  Kansas. It is expected that
drilling of the final two wells in the Eight Well Program will be completed in the first
quarter of 2006.

In
October, 2005 the Company accepted an exchange from Hoactzin Partners, L.P.
(Hoactzin) of promissory notes made by the Company in the principal amount of
$2,514,000 for a 94.3% working interest in a twelve well drilling program (the
Twelve Well Program) by the Company on its Kansas Properties. The Company
retained the remaining 5.7% working interest in the Twelve Well Program. The promissory
notes exchanged were originally issued by the Company in connection with loans made to the
Company by Dolphin Offshore Partners, L.P. (Dolphin) to fund the
Companys cash exchange to holders of its Series A, B and C Preferred Stock. Peter E.
Salas, the Chairman of the Board of Directors of the Company, is the controlling person of
Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management,
Inc., the general partner of Dolphin, which is the Companys largest shareholder.

Under
the terms of the Twelve Well Program, once Hoactzin receives total proceeds from its
working interest in the Program in the amount of $3,016,800, Hoactzin will pay the Company
a management fee equal to 85% of the net revenues attributable to its working interest in
the Program for the remaining life of the twelve wells. In addition, the Company has an
option expiring March 31, 2006 to repurchase from Hoactzin the obligation to drill the
final six wells of the Twelve Well Program by paying to Hoactzin an amount equal to one
half of the principal amount of the notes exchanged by Hoactzin, plus interest on that
amount at 6% per annum until the date of repurchase, and granting to Hoactzin a 1/16
overriding royalty in both the six wells existing at the time of repurchase and the next
six wells in the Program drilled by the Company.

As
of December 31, 2005, three of the wells in the Twelve Well Program had been drilled.
Although one of the three wells was a dry hole, the two other wells have resulted in
commercial production with one well which was completed on November 16, 2005 having
produced a total of 1,030 barrels of oil through December 31, 2005 and the other well
which was only recently completed having production of approximately 40 barrels of oil per
day. See, Item 2 Properties  Oil and Gas Drilling Activities 
Kansas.

There
are also several capital development projects that the Company is considering to increase
current oil production with respect to the Kansas Properties, including

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recompletion ofwells and major workovers. Management has made the decision to simultaneously undertake as
many of these projects that can be paid from the Companys current cash flow as soon
as the Company is able to obtain third party crews and equipment to perform the work. To
date, a limited number of workovers on the Companys oil wells in Kansas has been
successful. The workovers included a treatment of wells by injection of polymers (a type
of plastic compound) that has sealed off almost all of the water from entering the fluid
stream that is naturally produced from the wells, while at the same time increasing the
total quantity of crude oil that is actually produced per day from the treated wells.
Although there can be no assurances, similar workovers when completed might reduce water
production and its associated removal expense and increase oil production from many of the
Companys other existing oil wells in Kansas.

# 2. The Tennessee
Properties

Amoco
Production Company, during the late 1970s and early 1980s acquired
approximately 50,500 acres of oil and gas leases in the Eastern Overthrust in the
Appalachian Basin, including the area now referred to as the Swan Creek Field. In 1982,
Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the
Knox Formation. These wells, once completed, had a high pressure and apparent volume of
deliverability of natural gas. In the mid-1980s, however, development of this Field
was cost prohibitive due to a substantial decline in worldwide oil and gas prices which
was further exacerbated by the high cost of constructing a necessary 23-mile pipeline
across three rugged mountain ranges and crossing the environmentally protected Clinch
River from Sneedville, Tennessee to deliver gas from the Swan Creek Field to the closest
market in Rogersville, Tennessee. In 1987, Amoco farmed out its leases to Eastern American
Energy Company which held the leases until July 1995. In July 1995, the Company concluded
a legal action under state law and acquired the Swan Creek leases.

# A. Swan Creek Pipeline
Facilities

In
July 1998, the Company completed Phase I of its pipeline from the Swan Creek Field, a
30-mile pipeline made of six and eight-inch steel pipe running from the Swan Creek Field
into the main city gate of Rogersville, Tennessee. The Company utilized the Tennessee
Valley Authoritys already cleared right-of-way along its main power line grid for
most of the pipeline being laid 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
March 2001, construction of Phase II of the Companys pipeline system was completed.
Phase II was an additional 35 miles of eight and 12-inch pipe laid at a cost of
approximately $12.1 million, extending the Companys pipeline from a point near the
terminus of Phase I and connecting to meter station at Eastman Chemical Companys
(Eastman) plant in Kingsport, Tennessee. The completed pipeline system extends
65 miles from the Companys Swan Creek Field to Kingsport, Tennessee and was built
for a total cost of approximately $16,329,552.

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# B. Swan Creek
Production and Development

In
2003 management had obtained state regulatory approval for drilling additional infield
wells in the Swan Creek Field resulting in an increased density of wells. Management
expected that an increased density of wells within the existing Swan Creek Field would
result in additional reserves and reported those reserves as proven in accordance with
reservoir engineering standards.

In
2004, the Company drilled and tested two new infield development wells in the Swan Creek
Field to the Knox Formation. This resulted in one producing well, the Steve Lawson #8. The
other well, the Hazel Sutton #3, did not result in the production of commercial volumes of
gas. An attempt was made to have this well produce oil from the Trenton formation, a
shallower interval, but this also proved unsuccessful. The Company does not believe it is
likely that commercial quantities of oil or gas will occur from the Hazel Sutton #3 well
and the well has remained shut-in in 2005 to maintain the pressure in the Stones River
Formation while oil production continues in surrounding wells. At such time in the future
as the pressure maintenance is no longer needed, it is anticipated that this well will
produce a small volume of gas. See, Item 2, Properties  Oil and Gas Drilling
Activities  Tennessee.

Contrary
to the expectations for additional infield developmental wells, drilling and testing
results of the two wells drilled in 2004 together with the accumulation of data from
previously drilled wells and seismic data indicated that drilling new gas wells in the
Swan Creek Field will not contribute to achieving any significant increase in daily gas
production totals from the Field; the current wells in production in the Swan Creek Field
would be capable of and would likely produce all the remaining reserves in that Field;
and, that only limited additional gas reserves could be added with additional infield
developmental drilling. Consequently, the Company does not have any plans at the present
time to drill any new gas wells in the Swan Creek Field.

Also,
because of the drilling results of these wells and accumulated data, the proven reserves
previously associated with the increased number of infield developmental wells in 2003
were not included in the proven reserves reported by the Company in 2004, resulting in a
decrease in volume from 16.3 BCF in 2003 to 6.7 BCF in 2004 of total proven gas reserves
in the Swan Creek Field. This substantial change was almost entirely related to
undeveloped locations that management now believes do not have a likelihood of being
drilled in the future, and was not related in any manner to the natural decline in
production experienced in 2004 from existing wells in the Swan Creek Field. In 2005, as
production in the Swan Creek Field, less expected normal production declines, remained
stable proven gas reserves in the Field decreased slightly to 6.3 BCF.

Based
on the foregoing, the Company now expects that even if new wells were drilled in the Swan
Creek Field, the deliverability of natural gas from the Field will not be sufficient to
satisfy the volumes deliverable under its contracts with Eastman and BAE

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in Kingsport,Tennessee. The Eastman contract provides that Eastman will buy a minimum of the lesser of
eighty percent of that customers daily usage or 10,000 MMBtu per day, and the BAE
contract provides that BAE will buy a minimum of all of that customers usage or
5,000 MMBtu per day after Eastmans volumes have been provided. The Companys
current production from the Swan Creek field is approximately 502 MMBtu per day. The
Companys contracts with these customers are only for gas produced from the Swan
Creek Field. So long as that Field is not capable of supplying these volumes, the Company
is not in breach or violation of these contracts. No penalty is associated with the
inability of the Field to produce the volumes that the Company could deliver and buyers
would be obligated to buy under its industrial contracts if the volumes were physically
available from the Field. However, in the event that the Company were found to be in
breach of its obligations for failure to deliver any volumes of gas that is produced from
the Swan Creek Field to either of these customers, the agreements limit potential exposure
to damages. Damages are limited to no more than $.40 per MMBtu for any replacement volumes
that are proved in a court proceeding as having been obtained to replace volumes required
to be furnished but not furnished by the Company.

The
experienced decline in actual production levels from existing wells in the Swan Creek
Field from 2004 to 2005 was expected and does not diminish either the shut-in pressure or
the Companys proved producing reserves in the Swan Creek Field. The declines,
however, suggest the production rates from some of the Companys wells will continue
to be slower, which may result in such wells lasting longer than originally expected.
Although there can be no assurance, the Company expects these natural rates of decline
will be less than the decline experienced to date, and that ongoing production from
existing wells will tend to stabilize near current production levels. The Company
anticipates that the natural decline of production from existing wells is now predictable
in the Swan Creek Field, and that proven producing reserves can be extracted primarily
through existing wells; however, at a rate slower than previously anticipated.

Natural
gas production from the Swan Creek Field during 2005 averaged 502 Mcf per day compared to
611 Mcf per day in 2004.

During
2005, the Company had 21 producing gas wells and 5 producing oil wells in the Swan Creek
Field. Miller Petroleum, Inc. and others had a participating interest in 7 of these wells.
See, Item 2  Properties  Property Location, Facilities, Size and Nature
of Ownership. In total, the Company has completed 47 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,
12 are not producing commercial quantities of hydrocarbons and will not be tied in to the
Companys pipeline since the expense of connection is not justified in view of the
expected volumes to be produced.

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# 3.Other Areas of
Development

The
Company has evaluated other geological structures in the East Tennessee area that are
similar to the Swan Creek Field. These target evaluations were made using available third
party seismic data, the Companys own seismic investigations, and drilling results
and geophysical logs from the existing wells in the region. While these areas are of
interest, and may be further evaluated at some future time, based on its review to date
the Company does not currently intend to actively explore these areas with its own funds.
However, the Company may consider entering into partnerships where further exploration and
drilling costs can be largely borne by third parties. There can be no assurances that any
third party would participate in a drilling program in these structures, that any of these
prospects will be drilled, and if they were drilled that they would result in commercial
production.

The
Company is seeking to purchase and has attempted to acquire additional existing oil and
gas production in the Mid-Continent (USA) area. The Company is particularly interested in
areas of Kansas, Oklahoma, and Texas. Although financing plans are uncertain, management
believes that when a suitable property becomes available, a combination of such a property
with our current reserves would allow the Company to create a financing mechanism that
would make a purchase of the property possible. However, there is no assurance that a
suitable property will become available or that terms will be established leading to a
completion of such a purchase.

The
Company also intends to establish and explore all business opportunities for connection of
the pipeline system owned by the Companys subsidiary, TPC, to other sources of
natural gas so that revenues from third parties for transportation of gas across the
pipeline system may be generated. Although no assurances can be made, such connections may
also enable the Company to purchase natural gas from other sources and to then market
natural gas to new customers in the Kingsport, Tennessee area at retail rates under a
franchise agreement already granted to the Company by the City of Kingsport, subject to
approval by the Tennessee Regulatory Authority.

The
Company also intends to explore the feasibility of obtaining natural gas or substitutes
for natural gas from unconventional sources if such gas can be economically treated and
tendered in commercial volumes for transportation through the Companys existing
pipeline system or other delivery mechanisms for the purposes of supplementing the
Companys existing supply to existing customers, and sale to additional customers.

# 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.

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# Principal Products or
Services and Markets

The
principal markets for the Companys crude oil are local refining companies, local
utilities and private industry end-users. The principal markets for the Companys
natural gas are local utilities, private industry end-users, and natural gas marketing
companies.

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 necessary property rights for
the pipeline system. The Companys pipeline can not only provide transportation
service for gas produced from the Companys wells, but could provide transportation
of gas for small independent producers in the local area as well. The Company could,
although there can be no assurance, sell its products to certain local towns, industries
and utility districts.

At
present, crude oil is sold to the Coffeyville Resources Refining and Marketing, LLC
(Coffeyville Refining) in Kansas City, Kansas. Coffeyville Refining is solely
responsible for transportation of the oil it purchases. The Company may sell some or all
of its production to one or more additional refineries in order to maximize revenues as
purchase prices offered by the refineries fluctuate from time to time.

# Drilling Equipment

The
Company does not currently own a drilling rig or any related drilling equipment. The
Company obtains drilling services as required from time to time from various companies as
available in the Swan Creek Field area and various drilling contractors in Kansas.

# 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.

The
Company has numerous competitors in the State of Tennessee that are in the business of
exploring for and producing oil and natural gas in the Kentucky and East Tennessee areas.
Some of these companies are larger than the Company and have greater financial resources.
These companies are in competition with the Company for lease positions in the

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known producing areas in which the Company currently operates, as well as other potential areas
of interest.

There
are numerous producers in the area of the Kansas Properties. Some are larger with greater
financial resources.

Although
management does not foresee any difficulties in procuring contracted drilling rigs,
several factors, including increased competition in the area, may limit the availability
of drilling rigs, rig operators and related personnel and/or equipment in the future. Such
limitations would have a natural adverse impact on the profitability of the Companys
operations.

The
Company anticipates no difficulty in procuring well drilling permits in any state. 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.

# Sources and Availability
of Raw Materials

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.

# Dependence On One or a
Few Major Customers

The
Company is presently dependent upon a small number of customers for the sale of gas from
the Swan Creek Field, principally Eastman and BAE, and other industrial customers in the
Kingsport area with which the Company may enter into gas sales contracts.

At
present, crude oil from the Kansas Properties is being purchased at the well and trucked
by Coffeyville Refining which is responsible for transportation of the crude oil
purchased. The Company may sell some or all of its production to one or more additional
refineries in order to maximize revenues as purchase prices offered by the refineries
fluctuate from time to time.

# 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.

10

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# Need For Governmental
Approval of Principal Products or Services

None
of the principal products offered by the Company require governmental approval, although
permits are required for drilling oil or gas wells. In addition 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
common carriers or utilities in the State of Tennessee. TPC presently has all required
tariffs and approvals necessary to transport natural gas to all customers of the Company.

The
City of Kingsport, Tennessee has enacted an ordinance granting to TPC 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 would be granted,
there can be no assurances that it would be granted, or that such approval would be
granted in a timely manner, or that such approval would not be limited in some manner by
the Tennessee Regulatory Authority.

# 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.

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 to 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 the Company believes that it is in compliance
with the laws of the State of Kansas.

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

11

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make 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 it may produce and
sell. In addition, at the 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.

The
Companys operations are also subject to numerous and frequently changing laws and
regulations governing the discharge of materials into the environment or otherwise
relating to environmental protection. The Company owns or leases, and has in the past
owned or leased, properties that have been used for the exploration and production of oil
and gas and these properties and the wastes disposed on these properties may be subject to
the Comprehensive Environmental Response, Compensation and Liability Act, the Oil
Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water
Pollution Control Act and analogous state laws. Under such laws, the Company could be
required to remove or remediate previously released wastes or property contamination.

Laws
and regulations protecting the environment have generally become more stringent and, may
in some cases, impose strict liability for environmental damage. Strict
liability means that the Company may be held liable for damage without regard to whether
it was negligent or otherwise at fault. Environmental laws and regulations may expose the
Company to liability for the conduct of or conditions caused by others or for acts that
were in compliance with all applicable laws at the time they were performed. Failure to
comply with these laws and regulations may result in the imposition of administrative,
civil and criminal penalties.

While
management believes that the Companys operations are in substantial compliance with
existing requirements of governmental bodies, the Companys ability to conduct
continued operations is subject to satisfying applicable regulatory and permitting
controls. The Companys current permits and authorizations and ability to get future
permits and authorizations may be susceptible, on a going forward basis, to increased
scrutiny, greater complexity resulting in increased costs or delays in receiving
appropriate authorizations.

The
Companys Board of Directors has 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. 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.

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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.

# Research and Development

The
Company has not expended any material amount in research and development activities during
the last two fiscal years.

# Number of Total
Employees and Number of Full-Time Employees

The
Company presently has twenty-three full time employees and no part-time employees.

# Executive Officers of
the Registrant

# Identification of
Executive Officers

The
following table sets forth the names of all current executive officers of the Company.
These persons will serve until their successors are elected or appointed and qualified, or
their prior resignations or terminations.

|Name                           | Positions Held | Date of Initial Election or Designation
|------------------------------ | -------------- | ---------------------------------------
|Jeffrey R. Bailey              |                | Chief Executive                        
|2306 West Gallaher Ferry       |                | Officer (1)                            
|Knoxville, TN 37932            |               
|Mark A. Ruth                   |                | Chief Financial                        
|9400 Hickory Knoll Lane        |                | Officer                                
|Knoxville, TN 37931            |               
|Robert M. Carter               |                | President Tengasco                     
|760 Prince George Parish Drive |                | Pipeline Corporation                   
|Knoxville, TN 37931            |               
|Cary V. Sorensen               |                | Vice-President;                        
|5517 Crestwood Dr.             |                | General Counsel;                       
|Knoxville, TN 37914            |                | Secretary                              

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Effective January 1, 2005, the
Company merged all duties of the Chief Executive Officer with and into the office of
President of the Company, held by Jeffrey R. Bailey, and the position of Chief Executive
Officer was eliminated. On November 18, 2005, the Company again established the office of
Chief Executive Officer and appointed Mr. Bailey to serve in that capacity. The separate
title and office of President was not retained by the Company.

# Business
Experience(2)

Mark
A. Ruth is 47 years old. He is a Certified Public Accountant with 24 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. On December 14, 1998 he
became the Companys Chief Financial Officer.

Robert
M. Carter is 69 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 57 years old. He is a 1976 graduate of the University of Texas School of
Law and has undergraduate and graduate degrees form North Texas State University and
Catholic University in Washington, D.C. Prior to joining the Company in July 1999, he had
been continuously engaged in the practice of law in Houston, Texas relating to the energy
industry since 1977, both in private law firms and a corporate law department, 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 pipeline and other 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 nine states. These matters involved gas contracts, gas marketing,
and 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.

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# Code of Ethics

The
Companys Board of Directors has adopted a Code of Ethics that applies to the
Companys financial officers and executive officers, including its Chief Executive
Officer and Chief Financial Officer. A copy of this Code of Ethics can be found at the
Companys internet website at www.tengasco.com. The Company intends to disclose any
amendments to its Code of Ethics, and any waiver from a provision of the Code of Ethics
granted to the Companys President, Chief Financial Officer or persons performing
similar functions, on the Companys internet website within five business days
following such amendment or waiver. A copy of the Code of Ethics can be obtained free of
charge by writing to: Cary V. Sorensen, Secretary, Tengasco, Inc., 10215 Technology Drive,
Suite 301, Knoxville, TN 37932.

# Available Information

The
Company is a reporting company, as that term is defined under the Securities Acts, and
therefore, files reports, including Quarterly Reports on Form 10-Q and Annual Reports on
Form 10-K such as this Report, proxy information statements and other materials with the
Securities and Exchange Commission (SEC). You may read and copy any materials
the Company files with the SEC at the SECs Public Reference Room at 450 Fifth
Street, N.W., Washington D.C. 20549 upon payment of the prescribed fees. You may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.

In
addition, the Company is an electronic filer and files its Reports and information with
the SEC through the SECs Electronic Data Gathering, Analysis and Retrieval system
(EDGAR). The SEC maintains a Web site that contains reports, proxy and
information statements and other information regarding issuers that file electronically
through EDGAR with the SEC, including all of the Companys filings with the SEC. The
address of such site is http://www.sec.gov.

The
Companys website is located at http://www.tengasco.com. Under the
Finance section of the website, you may access, free of charge the
Companys Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports
on Form 8-K, Section 16 filings (Form 3, 4 and 5) and any amendments to those reports as
reasonably practicable after the Company electronically files such reports with the SEC.
The information contained on the Companys website is not part of this Report or any
other report filed with the SEC.

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# ITEM 1A. RISK FACTORS

In
addition to the other information included in this Form 10-K, the following risk factors
should be considered in evaluating the Companys business and future prospects. The
risk factors described below are not necessarily exhaustive and you are encouraged to
perform your own investigation with respect to the Company and its business. You should
also read the other information included in this Form 10-K, including the financial
statements and related notes.

# The Companys
Growth and Development is Dependent Upon its Finding and Maintaining  an Arrangement with an
Institutional Lender

The
Company must make substantial 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, drill new wells and
acquire new properties is dependent upon the Companys ability to fund these
expenditures. Unless the Company is able to obtain and maintain institutional financing,
the Company will have to obtain the necessary funds to proceed with the Companys
operations from its operating revenues and other sources, such as equity investments or
joint ventures with other companies. In addition, the Companys revenues or cash
flows could decline in the future because of a variety of reasons, including lower oil and
gas prices or the inoperability of some or all of the Companys existing wells. If
the Companys revenues or cash flows decrease or the Company is unable to maintain
its institutional financing arrangements, the Company would be required to reduce
production over time or would otherwise be adversely affected, which would adversely
impact the Companys ability to operate successfully. In the event that the Company
is not the majority owner or operator of an oil and gas project, the Company may have no
control over the timing or amount of capital expenditures required with the particular
project. If the Company cannot fund the Companys capital expenditures in such
projects, the Companys interests in such projects may be reduced or forfeited.

# The Company has a
History of Significant Losses

During
the early stages of the development of its oil and gas business the Company has had a
history of significant losses from operations and has an accumulated deficit of
$32,297,496 and a working capital deficit of $1,334,744 as of December 31, 2005. Although
management has substantially reduced its cash operating expenses, these losses have had a
material adverse impact on the operations of the Companys business. In the event the
Company experiences such losses in the future it may curtail the Companys
development activities or force the Company to sell some of its assets in an untimely
fashion or on less than favorable terms.

16

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# Declines In Oil and
Gas Prices Will Materially Adversely Affect the Company.

The
Companys future financial condition and results of operations will depend in part
upon the prices obtainable for the Companys oil and natural gas production and the
costs of finding, acquiring, 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 Companys
control. These factors include worldwide political instability (especially in the Middle
East and other oil-producing regions), the foreign supply of oil and gas, the price of
foreign imports, the level of drilling activity, the level of consumer product demand,
government regulations and taxes, the price and availability of alternative fuels and the
overall economic environment. A substantial or extended decline in oil and gas prices
would have a material adverse effect on the Companys financial position, results of
operations, quantities of oil and gas that may be economically produced, and access to
capital. Oil and natural gas prices have historically been and are likely to continue to
be volatile. This volatility makes it difficult to estimate with precision the value of
producing properties in acquisitions and to budget and project the return on exploration
and development projects involving the Companys oil and gas properties. In addition,
unusually volatile prices often disrupt the market for oil and gas properties, as buyers
and sellers have more difficulty agreeing on the purchase price of properties.

# There Are Risks In
Rates Of Oil and Gas Production,Development Expenditures, and Cash Flows.

Projecting
the effects of commodity prices on production, and timing of development expenditures
include many factors beyond the Companys control. The future estimates of net cash
flows from the Companys proved reserves and their present value are based upon
various assumptions about future production levels, prices, and costs that may prove to be
incorrect over time. Any significant variance from assumptions could result in the actual
future net cash flows being materially different from the estimates.

# Oil and Gas Operations
Involve Substantial Costs and are Subject to Various Economic Risks.

The
Companys oil and gas operations 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

17

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Companys investment in
such well(s) or property. In addition, the cost and timing of drilling, completing and
operating wells is often uncertain.

# Shortages of Oil Field
Equipment, Services and Qualified Personnel Could Adversely Affect Results of Operations.

The
demand for qualified and experienced field personnel to drill wells and conduct field
operations, geologists, geophysicists, engineers and other professionals in the oil and
natural gas industry can fluctuate significantly, often in correlation with oil and
natural gas prices, causing periodic shortages. There have also been shortages of drilling
rigs and other equipment, as demand for rigs and equipment has increased along with the
number of wells being drilled. These factors also cause significant increases in costs for
equipment, services and personnel. Higher oil and natural gas prices generally stimulate
increased demand and result in increased prices for drilling rigs, crews and associated
supplies, equipment and services. These shortages or price increases could adversely
affect the profit margin, cash flow and operating results or restrict the ability to drill
wells and conduct ordinary operations.

# Failure to Find or
Acquire Additional Reserves,Thus Reserves and Production Will Decline Materially From Their
Current Levels.

The
rate of production from oil and natural gas properties generally declines as reserves are
depleted. Except to the extent that the Company acquires additional properties containing
proved reserves, conducts successful exploration and development drilling, successfully
applies new technologies or identifies additional behind-pipe zones or secondary recovery
reserves, the Companys proved reserves will decline materially as reserves are
produced. Future oil and natural gas production is, therefore, highly dependent upon the
level of success in acquiring or finding additional reserves.

Drilling
for oil and natural gas may involve unprofitable efforts, not only from dry wells but also
from wells that are productive but do not produce sufficient net reserves to return a
profit after deducting drilling, operating and other costs. In addition, wells that are
profitable may not achieve a targeted rate of return. The Company relies on seismic data
and other technologies in identifying prospects and in conducting exploration activities.
The seismic data and other technologies used do not allow them to know conclusively prior
to drilling a well whether oil or natural gas is present or may be produced economically.

The
ultimate cost of drilling, completing and operating a well can adversely affect the
economics of a project. Further drilling operations may be curtailed, delayed or canceled
as a result of numerous factors, including unexpected drilling conditions, title problems,
pressure or irregularities in formations, equipment failures or accidents, adverse weather
conditions, environmental and other governmental requirements and the cost of, or
shortages or delays in the availability of, drilling rigs, equipment and services.

18

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# The Company has
Significant Costs 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 it may produce and
sell. In addition, at the 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.

# The Company has
Significant Costs Related to Environmental Matters.

The
Companys operations are subject to numerous and frequently changing laws and
regulations governing the discharge of materials into the environment or otherwise
relating to environmental protection. The Company owns or leases, and has owned or leased,
properties that have been leased for the exploration and production of oil and gas and
these properties and the wastes disposed on these properties may be subject to the
Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution
Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution
Control Act and similar state laws. Under such laws, the Company could be required to
remove or remediate wastes or property contamination.

Laws
and regulations protecting the environment have generally become more stringent and, may
in some cases, impose strict liability for environmental damage. Strict
liability means that the Company may be held liable for damage without regard to whether
it was negligent or otherwise at fault. Environmental laws and regulations may expose the
Company to liability for the conduct of or conditions caused by others or for acts that
were in compliance with all applicable laws at the time they were performed. Failure to
comply with these laws and regulations may result in the imposition of administrative,
civil and criminal penalties.

The
Companys ability to conduct continued operations is subject to satisfying applicable
regulatory and permitting controls. The Companys current permits and authorizations
and ability to get future permits and authorizations may be susceptible, on a going
forward basis, to increased scrutiny, greater complexity resulting in increased costs or
delays in receiving appropriate authorizations.

19

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# 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. Although 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,
insurance is not available to the Company against all operational risks.

# The Company is Not
Competitive with Respect to Acquisitions or Personnel.

The
oil and gas business is highly competitive. In seeking any suitable oil and gas properties
for acquisition, or drilling rig operators and related personnel and equipment, the
Company may not be able to compete with most other companies, including large oil and gas
companies and other independent operators with greater financial and technical resources
and longer history and experience in property acquisition and operation.

# The Company Depends on
Key Personnel, Whom it May Not be Ableto Retain or Recruit.

Members
of present management and certain Company employees have substantial expertise in the
areas of endeavor presently conducted and to be engaged in by the Company. To the extent
that their services become unavailable, the Company would be required to retain other
qualified personnel. The Company does not know whether it would be able to recruit and
hire qualified persons upon acceptable terms. The Company does not maintain Key
Person insurance for any of the Companys key employees.

# General Economic
Conditions.

Virtually
all of the Companys operations are subject to the risks and uncertainties of adverse
changes in general economic conditions, the outcome of pending and/or potential legal or
regulatory proceedings, changes in environmental, tax, labor and other laws and
regulations to which the Company is subject, and the condition of the capital markets
utilized by the Company to finance its operations.

# ITEM 1B. UNRESOLVED
STAFF COMMENTS

Not Applicable.

20

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ITEM
2. PROPERTIES

# Property Location,
Facilities, Size and Nature of Ownership

# General

The
Company leases its principal executive offices, consisting of approximately 4,607 square
feet located at 10215 Technology Drive, Suite 301, Knoxville, Tennessee at a rental of
$5,279 per month and an office in Hays, Kansas at a rental of $500 per month.

Although
the Company does not pay taxes on its Swan Creek leases, it pays ad-valorem taxes on its
Kansas Properties. The Company has general liability insurance for its Kansas and
Tennessee Properties.

# Kansas Properties

The
Kansas Properties as of December 31, 2005 contained 130 leases totaling 15,875 acres in
the vicinity of Hays, Kansas. The decrease in the total volume of acreage of the
Companys Kansas Properties from 42,895 acres at the end of 2004 is primarily due to
the sale on March 4, 2005 of the Companys gas producing properties located in Rush
County, Kansas. See, Item 1, Business  The Kansas Properties. The terms
on the Companys original leases in the Kansas properties were from 1 to 10 years.
Most of these leases, however, are still in effect because they are being held by
production. 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 maintains a 100% working
interest in most of its older wells and any undrilled acreage in Kansas.

In
February and March 2005, the Company began drilling the first two wells of its Eight Well
Program. As stated in Item 1 of this Report, the Company has a 19% working interest in the
eight wells in that Program and the former Series A shareholders retain the remaining 81%
working interest in those eight wells. However, under the terms of the Eight Well Program,
once the former Series A shareholders participating in that Program receive cash flow from
their working interest equaling 80% of the face value of the Series A Shares they
exchanged for their interests in the Program, thereafter, for the balance of the time
those wells remain productive, the Company will receive 85% of the cash flow from the 81%
working interest as a management fee and the Series A shareholders will receive the other
15% of the cash flow from the 81% working interest.

Hoactzin
Partners, L.P. (Hoactzin) retains a 94.3% in the Twelve Well Program on the
Kansas Properties with the Company retaining the remaining 5.7% working interest in that
Program. See, Item 1  Business  The Kansas Properties. Under the
terms of the Twelve Well Program once Hoactzin receives proceeds from its working interest
in the aggregate amount of $3,016,800, Hoactzin will pay the Company a management fee
equal to 85% of the net revenues attributable to its working interest in the Program for
the remaining life of the twelve wells. In addition, the Company has an option expiring
March 31, 2006 to repurchase from Hoactzin the obligation to drill the final six wells of
the Twelve Well Program by paying to Hoactzin an amount equal to one half of the principal
amount of the notes exchanged by Hoactzin, plus

21

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interest on that amount at 6% per annum
until the date of repurchase, and granting to Hoactzin a 1/16 overriding royalty in both
the six wells existing at the time of repurchase and the next six wells in the Program
drilled by the Company in Kansas. Hoactzin has agreed to extend the expiration date of the repurchase option from March 31, 2006 to an indefinite
future date being not later than the beginning of drilling of what would be the seventh well in the program if
the repurchase option has not been exercised.

# Tennessee Properties

The
Companys Swan Creek leases are on approximately 19,521 acres in Hancock, Claiborne
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.

Pioneer
Resources, Inc., an affiliate of Shigemi Morita, a former Director of the Company,
currently has a 25% overriding royalty in nine of the Companys existing wells, and a
50% overriding royalty and 6% overriding royalty, respectively, in two of the
Companys other existing wells. All of these wells are located in the Swan Creek
Field and all but two are presently producing wells.

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. Of these two wells, only the Stephen Lawson No. 1
continues to produce.

Another
individual has a 29% revenue interest in the Laura Jean Lawson No. 3 well by virtue of
having contributed her unleased acreage to the drilling unit and paying her proportionate
share of the drilling costs of the well. The Company was obligated to allow that
individual to participate on that basis in accordance with both customary industry
practice and the requirements of the procedures of the Tennessee Oil and Gas Board in a
forced pooling action brought by the Company to require the acreage to be included in the
unit so that the well could be drilled. The forced pooling procedure was concluded by her
contribution of acreage and agreement to pay her proportionate share of drilling costs.

The
Company also entered into a farmout agreement with Miller Petroleum, Inc.
(Miller) for ten wells to be drilled in the Swan Creek Field with the Company
having an option to award up to an additional ten future wells. All locations were to be
mutually agreed upon. Net revenues, as defined, were to be 81.25% to Miller. The
Companys subsidiary TPC will transport Millers gas. The Company reserved all
offset locations to wells drilled under the farmout agreement. All ten wells have been
drilled under the farmout agreement. The Company acquired back from Miller a 50% working
interest from Miller in nine of those ten wells in addition to its rights under the
farmout agreement. In addition, the Company and Miller have drilled two additional wells
on a 50-50 basis, although the Company declined to exercise its option for a ten-well
extension of the farmout agreement. Of the wells in which Miller owns an interest, six are
presently producing.

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Other
than the working interests described or referred to in this Item, the Company retains all
other working interests in wells drilled or to be drilled in the Swan Creek Field.

Other
working interest owners in oil and gas wells in which the Company has working interests
are entitled to market their respective shares of production to purchasers other than
purchasers with whom the Company has contracted. Absent such contractual arrangements
being made by the working interest owners, the Company is authorized but is not required
to provide a market for oil or gas attributable to working interest owners
production. At this time, the Company has not agreed to market gas for any working
interest owner to customers other than customers of the Company. If the Company were to
agree to market gas for working interest owners to customers other than the Companys
customers, the Company would have to agree, at that time, to the terms of such marketing
arrangements and it is possible that as a result of such arrangements, the Companys
revenues from such production may be correspondingly reduced. If the working interest
owners make their own arrangements to market their natural gas to other end users along
the Companys pipeline, such gas would be transported by TPC at published tariff
rates. The current published tariff rate is for firm transportation at a demand or
reservation charge of five cents per MMBtu per day plus a commodity charge of
$0.80 per MMBtu. If the working interest owners do not market their production, either
independently or through the Company, then their interest will be treated as not yet
produced and will be balanced either when marketing arrangements are made by such working
interest owners or when the well ceases to produce in accordance with customary industry
practice.

# Reserve Analyses

Ryder
Scott Company, L.P. of Houston, Texas (Ryder Scott) has performed reserve
analyses of all the Companys productive leases. Ryder Scott and its employees and
its registered petroleum engineers have no interest in the Company, and performed these
services at their standard rates. The net reserve values used hereafter were obtained from
a reserve report dated January 23, 2006 (the Report) prepared by Ryder Scott
as of December 31, 2005.

The
Report indicates the Companys TOTAL PROVEN ALL CATEGORIES reserves for
the Company to be as follows: net production volumes of 1,374,463 barrels of oil and 4,763
MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be
$37,179,112. The Report indicates the proven developed producing reserves for
the Company to be as follows: net production volumes of 1,091,135 barrels of oil and 2,814
MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be
$25,879,317.

In
substance, the Report used estimates of oil and gas reserves based upon standard petroleum
engineering methods which include production data, decline curve analysis, volumetric
calculations, pressure history, analogy, various correlations and technical factors.
Information for this purpose was obtained from owners of interests in the areas involved,
state regulatory agencies, commercial services, outside operators and files of Ryder
Scott.

23

---



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.

The
Company believes that the reserve analysis reports prepared by Ryder Scott for the
Companys Kansas and Tennessee Properties provide an essential basis for review and
consideration of the Companys producing properties by all potential industry
partners and all financial institutions across the country. It is standard in the industry
for reserve analyses such as these to be used as a basis for financing of drilling costs.

The
Company has not filed the reserve analysis reports prepared by Ryder Scott or any other
reserve reports with any Federal authority or agency other than the SEC. The Company,
however, has filed the information in the Report of the Companys reserves with the
Energy Information Service of the Department of Energy in compliance with that
agencys statutory function of surveying oil and gas reserves nationwide.

The
term Proved Oil and Gas Reserves is defined in Rule 4-10(a) (2) of Regulation
S-X promulgated by the SEC as follows:

|2. | Proved oil and gas reserves. Proved oil and gas reserves are the estimated
          quantities of crude oil, natural gas, and natural gas liquids which geological
          and engineering data demonstrate with reasonable certainty to be recoverable in
          future years from known reservoirs under existing economic and operating
          conditions, i.e., prices and costs as of the date the estimate is made. Prices
          include consideration of changes in existing prices provided only by contractual
          arrangements, but not on escalations based upon future conditions.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|i. | Reservoirs are considered proved if economic producibility is supported by
          either actual production or conclusive formation test. The area of a reservoir
          considered proved includes (A) that portion delineated by drilling and defined
          by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
          portions not yet drilled, but which can be reasonably judged as economically
          productive on the basis of available geological and engineering data. In the
          absence of information on fluid contacts, the lowest known structural occurrence
          of hydrocarbons controls the lower proved limit of the reservoir.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

24

---



|ii. | Reserves which can be produced economically through application of improved
          recovery techniques (such as fluid injection) are included in the proved
          classification when successful testing by a pilot project, or the operation of
          an installed program in the reservoir, provides support for the engineering
          analysis on which the project or program was based.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|iii. | Estimates of proved reserves do not include the following: (A) oil that may
          become available from known reservoirs but is classified separately as indicated
          additional reserves; (B) crude oil, natural gas, and natural gas liquids, the
          recovery of which is subject to reasonable doubt because of uncertainty as to
          geology, reservoir characteristics, or economic factors; (C) crude oil, natural
          gas, and natural gas liquids, that may occur in undrilled prospects; and (D)
          crude oil, natural gas, and natural gas liquids, that may be recovered from oil
          shales, coal, gilsonite and other such sources.
|---- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Production

The
following tables summarize for the past three fiscal years the volumes of oil and gas
produced, the Companys operating costs and the Companys average sales prices
for its oil and gas. The information includes volumes produced to royalty interests or
other parties working interests.

25

---



|     |  | TENNESSEE | 
|---- |  | --------- | 
|
|
|2005 |  |           | 
|     |  |           | 
|2004 |  |           | 
|     |  |           | 
|2003 |  |           | 
|     |  |           | 

|     |  | KANSAS | 
|---- |  | ------ | 
|
|
|2005 |  |        | 
|     |  |        | 
|2004 |  |        | 
|     |  |        | 
|2003 |  |        | 
|     |  |        | 

26

---



# Oil and Gas Drilling
Activities

In
2003, due to the Companys inability to raise capital because of its dispute with its
primary lender, Bank One, N.A., the Company did not have sufficient funds to drill any new
wells.

# Kansas

In
August 2004, the Company, based on 3D seismic data drilled one well in Kansas to the
Arbuckle formation, the Lewis #3. As of December 31, 2005, this well has produced
approximately 6,500 barrels of oil.

In
2005 the Company participated in the drilling of 9 new wells in Kansas. All of that
drilling was related to the either the Eight Well Program or the Twelve Well Program
described above. The results of drilling these nine wells has been favorable: 7 producing
wells and 2 dry holes. In the Eight Well Program, a total of 6 of the 8 wells to be
drilled were drilled in 2005. In the Twelve Well Program, three wells have been drilled in
2005 and early 2006. All wells in both Programs have produced in the aggregate a
cumulative total of 14,160 barrels.

| | The
results of the Eight Well Program as of December 31, 2005 are set out in the following
table:
| | -------------------------------------------------------------------------------------------------

|Name of Well        | Date Completed | Cumulative Production to Date
|------------------- | -------------- | -----------------------------
|DeYoung "A" #5      |                |                              
|                    |                |                              
|Dick "A" # 8        |                |                              
|                    |                |                              
|Ridgway "A" #4      |                |                              
|                    |                |                              
|Urban "A" # 6       |                |                              
|                    |                |                              
|Kraus "AA" # 3      |                |                              
|                    |                |                              
|Ben Tempero "A" # 3 |                |                              
|                    |                |                              

27

---



| | The
results of the Twelve Well Program as of December 31, 2005 are set out in the following
table:
| | --------------------------------------------------------------------------------------------------

|Name of Well | Date Well Completed | Cumulative Production to Date
|------------ | ------------------- | -----------------------------
|Keenan B # 6 |                     |                              
|             |                     |                              
|Foster B # 9 |                     |                              
|             |                     |                              
|Lowry        |                     |                              
|             |                     |                              

The
Company continues to pursue incremental production increase where possible in the older
wells, by using recompletion techniques to enhance production from currently producing
intervals.

# Tennessee

In
2004 the Company drilled two wells in the Swan Creek Field which resulted in one producing
well, the Steve Lawson #8. This well was completed as a Knox gas well with an average
monthly production of approximately 235 Mcf. The other well, the Hazel Sutton #3 was
drilled to the Knox formation, but did not result in the production of commercial volumes
of gas. An attempt was made to have this well produce oil from the Trenton formation, a
shallower interval, but this also proved unsuccessful as the wellbore encountered
technical problems. The Company does not believe it is likely that commercial quantities
of oil or gas will occur from this well.

In
2005, the Company did not drill any new wells in the Swan Creek Field. The Company
believes that drilling new gas wells in the Field will not contribute to achieving any
significant increase in daily gas production totals from the Field. As a result, the
Company does not have any plans at the present time to drill any new gas wells in the Swan
Creek Field.

# Gross and Net Wells

The
following tables set forth for the fiscal years ending December 31, 2003, 2004, and 2005
the number of gross and net development wells drilled by the Company. The wells drilled in
2005 all refer to the wells drilled in the Eight and Twelve Well

28

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Programs in Kansas. The
dry holes set forth in the table below are the one each from the Eight and Twelve Well
Programs and the Hazel Sutton #3 wells drilled in Tennessee 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.



|YEAR ENDED DECEMBER 31
|----------------------
|                      
|                      
|Tennessee             
|Productive Wells      
|Dry Holes             
|Kansas                
|Productive Wells      















|Dry Holes | 2 | 0.2163 | 0 | 0 | 0 | 0
|--------- | - | ------ | - | - | - | -











29

---



# Productive Wells

The
following table sets forth information regarding the number of productive wells in which
the Company held a working interest as of December 31, 2005. 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
|--------- | --- | ---
|
|Tennessee |     |    
|          |    
|Kansas    |     |    
|          |     |    
|          |     |    

# Developed and
Undeveloped Oil and Gas Acreage

As
of December 31, 2005, the Company owned working interests in the following developed and
undeveloped oil and gas acreage. Net acres refer to the Companys interest less the
interest of royalty and other working interest owners.

|          | DEVELOPED | UNDEVELOPED
|--------- | --------- | -----------
|
|Tennessee |           |            
|          |           |            
|Kansas    |           |            
|          |           |            

30

---



# ITEM 3. LEGAL PROCEEDINGS

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.

# ITEM 4. SUBMISSION OF
MATTERS TO A VOTE OF SECURITY HOLDERS

None
during the fourth quarter of 2005.

# PART II

# ITEM 5. MARKET FOR
REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

# 

# 

# Market Information

| | The
Companys common stock is listed on the American Stock Exchange (AMEX)
under the symbol TGC. The range of high and low closing prices for shares of common stock
of the Company during the fiscal years ended December 31, 2005 and December 31, 2004 are
set forth below.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|For the Quarters Ending | High | Low
|----------------------- | ---- | ---
|March 31, 2005          |      |    
|June 30, 2005           |      |    
|September 30, 2005      |      |    
|December 31, 2005       |      |    
|March 31, 2004          |      |    
|June 30, 2004           |      |    
|September 30, 2004      |      |    
|December 31, 2004       |      |    

31

---



# Holders

As
of March 1, 2006 the number of shareholders of record of the Companys common stock
was 352 and management believes that there are approximately 5,181 beneficial owners of
the Companys common stock.

# Dividends

The
Company did not pay any dividends with respect to the Companys common stock in 2005
and has no present plans to declare any further dividends with respect to its common
stock.

# Recent Sales of
Unregistered Securities

During
the fourth quarter of fiscal 2005, the Company issued 5,230 shares of its common stock
pursuant to the exercise of warrants issued by the Company to members of the plaintiff
class as part of the settlement of the action entitled Paul Miller v. M. E. Ratliff and
Tengasco, Inc., United States District Court for the Eastern District of Tennessee,
Knoxville, Docket Number 3:02-CV-644. Those warrants are exercisable for a period of three
years from date of issue at $0.45 per share and are exempt from registration pursuant to
section 3(a)(10) of the Securities Act of 1933, as amended. Any unregistered equity
securities that were sold or issued by the Company during the first three quarters of
Fiscal 2005 were previously reported in Reports filed by the Company with the SEC.

# Purchases of Equity
Securities by the Company and Affiliated
Purchasers

# 

Neither
the Company or any of its affiliates repurchased any of the Companys equity
securities during 2005.

32

---



# Equity Compensation Plan
Information

The
following table sets forth information regarding the Companys equity compensation
plans as of December 31, 2005.

|                    |  |                      | 
|------------------- |  | -------------------- | 
|Plan Category       |  | Number of securities | 
|                    |  | to be issued upon    | 
|                    |  | exercise of          | 
|                    |  | outstanding options, | 
|                    |  | warrants and rights  | 
|                    |  |                      | 
|                    |  |                      | 
|                    |  | (a)                  | 
|                    |  |                      | 
|Equity compensation | 
|plans approved by   | 
|security holders(7) |  | 2,584,000            | 
|                    |  |                      | 
|Equity compensation | 
|plans not approved  | 
|by security holders |  | 0                    | 
|                    |  |                      | 
|Total               |  | 2,584,000            | 
|                    |  |                      | 

33

---



# ITEM 6. SELECTED
FINANCIAL DATA

The
following selected financial data has been derived from the Companys financial
statements, and should be read in conjunction with those financial statements, including
the related footnotes.

Years Ended December
31,(8)

|                              | 2005 | 2004 | 2003 | 2002      | 2001
|----------------------------- | ---- | ---- | ---- | --------- | ----
|Income Statement Data:        |      |      |      |           |     
|                              |      |      |      |           |     
|Oil and Gas Revenues          |      |      | $    | 7,067,790 |     
|                              |      |      |      |           |     
|Production Costs and Taxes    |      |      | $    | 3,046,460 |     
|                              |      |      |      |           |     
|General and Administrative    |      |      | $    | 1,322,616 |     
|                              |      |      |      |           |     
|Interest Expense              |      |      | $    | 472,655   |     
|                              |      |      |      |           |     
|Net Income/Loss               |      |      | $    | 1,088,028 |     
|                              |      |      |      |           |     
|Net Income/Loss               |      |      | $    | 1,088,028 |     
|Attributable to Common        |      |     
|Stockholders                  |      |     
|                              |      |      |      |           |     
|Net Income/Loss  Attributable |      |      | $    | 0.02      |     
|to  Common  Stockholders  Per |      |     
|Share                         |      |     

34

---



As of December 31,
(9)(10)

|                            | 2005 | 2004 | 2003 | 2002       | 2001
|--------------------------- | ---- | ---- | ---- | ---------- | ----
|Balance Sheet Data:         |      |      |      |            |     
|                            |      |      |      |            |     
|Working Capital Deficit     |      |      | $    | (1,334,744 | )   
|                            |      |      |      |            |     
|Oil and Gas Properties, Net |      |      | $    | 9,675,877  |     
|                            |      |      |      |            |     
|Pipeline Facilities, Net    |      |      | $    | 13,994,453 |     
|                            |      |      |      |            |     
|Total Assets                |      |      | $    | 25,908,616 |     
|                            |      |      |      |            |     
|Long-Term Debt              |      |      | $    | 117,912    |     
|                            |      |      |      |            |     
|Redeemable Preferred Stock  |      |      | $    | -0-        |     
|                            |      |      |      |            |     
|Stockholders Equity         |      |      | $    | 21,961,454 |     
|                            |      |      |      |            |     

# ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

# >Results of Operations

The
Company incurred a net income to holders of common stock of $1,088,028 or $0.02 per share
in 2005 compared to a net loss of $1,994,025 ($0.05 per share) in 2004 and compared to a
net loss of $3,451,580 ($0.29 per share) in 2003.

The
Company realized oil and gas revenues of $7,076,790 in 2005 compared to $6,013,374 in 2004
and compared to $6,040,872 in 2003. Revenues increased $1,163,416 from 2004 due primarily
to increases in oil prices and the Companys net oil production in Kansas increase of
approximately 4,400 bbls over 2004 levels. The Company has offset the normal decline curve
in its Kansas properties with additional drilling and well workovers. The gross volumes of
oil of 134,164 bbls would have been approximately 103,000 bbls without additional drilling
and well workovers. The Company sold 118,088 bbls of oil in 2004 and 122,954 in 2003. The
volume of gas sold from the Swan Creek Field decreased to 183,399 Mcf in 2005 from 223,078
Mcf in 2004 and the volume of oil sold from Swan Creek Field decreased to 10,388 barrels
in 2005 from 13,515 barrels in 2004. The decline in volumes of oil and gas produced in the
Swan Creek Field from existing wells is normal for producing wells and the declines as
experienced were not unexpected. The decrease in volumes was offset by increases in price
of the oil and gas sold. The Companys gas production in Kansas was only for the
month of January (20,729 mcf) as the Companys Kansas gas field was sold on March 4,
2005 with the buyers production being retroactive to February 1, 2005. The Kansas
gas field had produced 261,446 Mcf of gas in 2004and 236,635 Mcf in 2003.

35

---



Gas
prices received for sales of gas from the Swan Creek Field averaged $8.74 per Mcf in 2005,
$6.13 in 2004, and $5.38 in 2003. Oil prices received for sales of oil from the Swan Creek
field averaged $53.90 per barrel in 2005, $36.57 in 2004, and $26.87 in 2003. Oil prices
received for sales of oil in Kansas averaged $53.48 per barrel in 2005, $39.41 in 2004,
and $29.00 in 2003.

The
Companys subsidiary, TPC, had pipeline transportation revenues of $94,911 in 2005,
$92,599 in 2004 and $163,393 in 2003. The decreases in revenues in 2005 and 2004 from 2003
resulted primarily from the decrease in volumes of gas produced from the Swan Creek Field.

Production
costs and taxes in 2005 of $3,046,460 have decreased from 2004 and 2003 levels of
$3,364,429 and $3,412,201 respectively, primarily as a reult to the sale of the Kansas gas
field.

Depletion,
depreciation, and amortization decreased to $1,605,043 in 2005 from $2,067,566 in 2004 and
$2,308,007 in 2003. The decrease is mainly due to depletion on the Kansas properties in
2004 and 2003 due to the sale of the Kansas gas field.

The
Companys general administrative costs of $1,322,616 increased slightly over 2004
levels of $1,177,183, but is still lower than 2003 levels of $1,486,280. However, it is
significant to note that the 2005 general administrative costs include a $84,030 non-cash
charge relating to stock options granted in 2005 and $45,000 in filing fees paid to the
American Stock Exchange due to the conversion of the Companys preferred stock to
common stock. Management has made a significant effort to control costs in every aspect of
its operations. Some of these cost reductions include the reduction of personnel from 2003
levels and utilization of existing employees to perform drafting and file preparation
services previously performed by third parties at additional cost.

Interest
expense for 2005 decreased significantly over 2004 and 2003 levels. The substantial
decrease is the result of the payoff in 2004 of the Companys loans from Bank One,
N.A. and Dolphin Offshore Partners, L.P. and the conversion in 2004 and 2005 of all the
Companys preferred stock, which was subject to mandatory redemption, into either
interests in a drilling program, common stock or cash payoffs. See, Liquidity and
Capital Resources below. As of December 31, 2005 the Companys only debt
financing is vehicle and equipment loans totaling $176,779.

The
Companys public relations costs remain stable at $30,020 for 2005, $35,347 for 2004
and $31,183 for 2003 as the Company applied cost saving methods in the preparation of its
annual report and in publishing of press releases.

Professional
fees in 2005 were $263,800 compared to $779,180 in 2004 and $549,503 in 2003. These fees
were greatly reduced in 2005 due to the settlement of the Companys litigation with
Bank One.

36

---



During
2003, the Company implemented Statement of Financial Accounting Standard
(SFAS) No. 150, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity (SFAS 150), resulting in
a gain on a cumulative effect from a change in accounting principle of $365,675.
Additionally, the Company implemented Statement of Financial Accounting Standard No. 143,
Asset Retirement Obligations in July 1, 2003, resulting in a loss on a
cumulative effect from a change in accounting principle of $351,204. See Notes to the
Consolidated Financial Statements in Item 8 of this report.

During
2004, the Company recorded a gain from extinguishment of debt in the amount of $336,820
from the Bank One litigation settlement and a gain on disposal of preferred stock of
$458,310. The Company also recorded a loss on sale of a drilling rig during 2004 of
$107,744. The Company recorded a gain on disposal of Preferred Stock of $655,746 in 2005.

The
Company recorded an impairment loss of $495,000 relating to an oil rig in 2003.

Dividends
on preferred stock decreased to $0 in 2005 and 2004 from $268,389 in 2003, as a result of
the Companys adoption of SFAS No.150 effective July 1, 2003. The 2003 amount
reflects dividends for the first six months of 2003. Dividends were charged against the
Companys liability, Shares subject to mandatory redemption. All
dividends and accretion were expensed in 2004 and 2005. See, Note 9 to the Companys
Consolidated Financial Statements for more information.

# Liquidity and Capital
Resources

Management
believes that the Companys foundation for it future growth began to solidify in
2004. In 2004, all material litigation involving the Company was resolved, eliminating the
substantial ongoing costs and expenses of such litigation. Capital restructuring began in
February 2004, when the Companys rights offering to its then-shareholders
successfully raised sufficient capital to pay in full all preexisting secured debt in the
amount of $3.8 million, most of which had been obtained at relatively high interest rates.
Also in early 2004 certain unsecured convertible notes entered into in 1998 in the
principal amount of $1.5 million were fully paid, and still other convertible notes
entered into in 2002 in the original principal amount of $650,000 were paid in full in
March 2004.

In
December, 2004 the Company completed an exchange offer to the thirteen holders of all of
the Companys Series A 8% Cumulative Convertible Preferred Stock (Series A
Shares) in the face value of $2,867,900. Seven of the thirteen holders elected the
cash exchange option, and the face value of $1,085,000 of Series A Shares was exchanged
for a cash payment of $723,369. The Company obtained funds for the exchange from cash on
hand and the proceeds of a loan from Dolphin Offshore Partners, L.P. (Dolphin)
the Companys largest shareholder. Peter E. Salas, the Chairman of the Companys
Board of Directors is the sole shareholder and controlling person of Dolphin Management,
Inc., the general partner of Dolphin.

37

---



The loan from Dolphin was in the form of a secured
note in principal amount of $550,000 bearing 12% interest per annum. Five of the thirteen
Series A shareholders selected a drilling program exchange option and on December 31, 2004
the face value of $1,582,900 of Series A Shares plus dividend value of $31,658 was
exchanged for 6.5 of the eight units in the Companys Eight Well Program. In December
2005 the last remaining Series A preferred shareholder exchanged his preferred stock for
cash on essentially identical terms as received by the other Series A owners who had
exchanged their shares for cash.

In
early 2005, the Company elected to sell its gas producing properties in Rush County,
Kansas for $2.4 million and to utilize all the net proceeds of the sale to pay down the
$2.5 million debt to Dolphin incurred by the Company to fund the settlement of the
litigation with the Companys former primary lender, Bank One N.A., in May, 2004.
This had the effect of reducing the principal balance of the note evidencing that loan
from $2.5 million to $150,000, correspondingly reducing the high interest payments on that
note and reducing the total secured debt owed by the Company to Dolphin to approximately
$700,000 as of March 31, 2005, consisting of the $150,000 remaining principal of the $2.5
million note, and the principal of the $550,000 note described above which evidenced the
loan from Dolphin the proceeds of which were used by the Company to fund the cash exchange
payment for the Series A Shares. On May 19, 2005, a replacement note in the principal
amount of $700,000 bearing interest at the rate of 12% per annum evidencing this secured
debt was issued by the Company to Dolphin (the $700,000 Note).

In
August 2005, all of the holders of the Companys Series B 8% and C 6% Cumulative
Convertible Preferred Stock (the Series B and Series C Shares) in the total
aggregate value of $5,113,045.39 consisting of face value, dividends, and interest
exchanged their Series B and C shares for cash or for the Companys common stock. The
cash option exchange provided for a cash payment equal to 66.67% of the face value
together with any unpaid accrued dividends. Holders of approximately 53.2% of the face
value of outstanding Series B and C Shares selected this option, exchanging preferred
shares having an aggregate value of $2,721,140.39 for cash payments totaling
$1,814,184.30. The Company obtained the funds for this exchange primarily from proceeds of
a loan of $1,814,000 from Dolphin evidenced by a secured promissory note bearing 12%
interest (the $1,814,000 Note).

The
second option offered to the holders of the Series B and C Shares was to exchange their
Series B and C Shares for four shares of the Companys common stock for each dollar
of the face value and unpaid accrued dividends and interest on their Series B and C
Shares. The holders of the remaining aggregate value of $2,391,905 or 46.8% of the Series
B and C shares including Dolphin selected this option. As a result, a total of 9,567,620
shares of the Companys common stock were issued to holders of Series B and C Shares.
Of this total number, 4,595,040 shares of unregistered common stock were issued to Dolphin
in exchange for the $1,148,760 in aggregate value of the Series B shares held by Dolphin.
As a result of this exchange, as of August 22, 2005 the Company no longer had any
preferred stockholders and no further obligations under the Series B and C shares.

38

---



On
October 5, 2005 the Company and Hoactzin Partners, L. P. signed an agreement whereby
Hoactzin surrendered the $700,000 and $1,814,000 Notes and exchanged the Companys
obligation to repay this principal amount of $2.514 million for a 94.275% working interest
in a new twelve well drilling program (the Twelve Well Program) to be
undertaken by the Company on its properties in Kansas. The Company retained the 5.725%
working interest in the Twelve Well Program not owned by Hoactzin. The principal of the
Notes exchanged by Hoactzin represented the funds paid by the Company for the previous
exchanges by holders of the Companys Series A, B, and C preferred stock of their
preferred stock for cash. The controlling person of Hoactzin Partners, L. P. is Peter E.
Salas, the Chairman of the Companys Board of Directors and the controlling person of
Dolphin. Under the terms of the Twelve Well Program, the Company retained an option
expiring March 31, 2006 to repurchase from Hoactzin the obligations to drill the final six
wells of the Twelve Well Program for one half of the principal of notes exchanged by
Hoactzin, plus interest on that amount at 6% per annum until the date of any repurchase,
plus a 1/16 overriding royalty to Hoactzin on all wells drilled in the Twelve Well
Program. Payout and management fee calculations would also be adjusted to reflect any
reduction to a six well program.  Hoactzin has agreed to extend the expiration date of the repurchase option from March 31, 2006 to an indefinite
future date being not later than the beginning of drilling of what would be the seventh well in the program if
the repurchase option has not been exercised.

As
a result of the above exchanges of preferred stock and notes for interests in the Eight
and Twelve Well Programs, as of December 31, 2005, the Company had reduced its liabilities
in the form of face amount of preferred stock and secured promissory notes from
approximately $16 million as of December 31, 2003 to $0, the Company no longer had any
preferred stock outstanding, and the Company no longer had any liens on any of its oil and
gas properties or pipelines. The Companys only substantial liability was its
contractual obligation to drill the wells in the Eight and Twelve Well Programs. As of
December 31, 2005, the Company had already drilled nine of those twenty wells. The
drilling costs for the first nine wells drilled in these Programs has been satisfied from
the Companys proceeds from operations and it is anticipated that the final eleven
wells in the Programs will be also be paid from operating revenues.

Net
cash provided by operating activities for 2005 was $2,113,763 compared to net cash used in
operating activities of ($370,137) in 2004. The Company recorded net income in 2005 of
$1,088,028 from a net loss of ($1,994,025) in 2004. The increase in the amount of cash
provided in operating activities in 2005 was due to the Companys net income for 2005
and was increased by non-cash depletion, depreciation, and amortization of $1,605,043,
non-cash compensation and services paid by insurance of equity instruments of $103,400 and
accretion of liabilities of $233,696. Cash flow used in working capital items in 2005 was
$155,324 compared to cash used in working capital items of $880,584 in 2004. This resulted
in 2005 from an increase in accounts receivable of $447,653, and an increase in inventory
of $154,586 offset by an increase in accounts payable of $277,458.

Net
cash used in operating activities for 2004 was $370,137 compared to net cash provided by
operating activities of $316,027 in 2003. The Companys net loss in 2004 decreased to
$1,994,025 from $3,197,662 in 2003.

39

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The impact on cash used in operating activities was
due to the net loss for 2004 and was primarily offset by non-cash depletion, depreciation,
and amortization of $2,067,566, non-cash compensation and services paid by insurance of
equity instruments of $82,500 and accretion of liabilities of $792,124. Cash flow used in
working capital items in 2004 was $880,584 compared to cash provided by working capital
items of $60,282 in 2003. This resulted in 2004 from decreases from 2003 in accounts
payable of $756,129, a decrease in other assets of $155,477, an increase in accounts
receivable of $198,374, and a decrease in accrued interest payable of $208,954.

Net
cash provided by investing activities amounted to $2,166,854 for 2005 compared to net cash
used in the amount of $876,854 for 2004. The net cash provided by investing activities
during 2005 was primarily attributable to the sale of the Kansas properties of $2,651,770
offset by increase in Kansas oil and gas properties net of the Kansas drilling programs
portion of $402,876.

Net
cash used in investing activities amounted to $876,854 for 2004 compared to net cash used
in the amount of $65,069 for 2003. The increase in net cash used for investing activities
during 2004 was primarily attributable to an increase in oil and gas properties of
$1,122,903 offset by a decrease in other property and equipment of $296,865.

Net
cash used in financing activities amounted to $4,287,383 in 2005 from net cash provided by
financing activities of $1,202,060 in 2004. In 2005 the primary use of funds was repayment
of borrowers of $3,182,636, repayment of redeemable liabilities of $4,241,874, repayment
of drilling programs of $1,945,203 offset by proceeds from issuance of common stock of
$2,391,905 and a new drilling program of $2,514,000 and proceeds from borrowing of
$155,073.

Net
cash provided by financing activities increased to $1,202,060 in 2004 from cash used in
financing activities of $122,422 in 2003. In 2004 the primary sources of financing
included proceeds from borrowings of $3,310,815 compared to $3,256,171 in 2003. The
primary use of cash in financing activities in 2004 was the use of funds received from the
rights offering of $8,848,341 to repay the Companys prior borrowings of $9,848,560.
In 2003 cash from financing activities of $3,432,470 was used primarily to make payments
to Bank One in 2003 and for working capital.

# Critical Accounting
Policies

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

40

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statements and the uncertainties that could impact
the Companys results of operations, financial condition and cash flows.

# Revenue Recognition

The
Company recognizes revenues based on actual volumes of oil and gas sold and delivered to
its customers. Natural gas meters are placed at the customers location and usage is
billed each month. Crude oil is stored and at the time of delivery to the customers,
revenues are recognized.

# Full Cost Method of
Accounting

The
Company follows the full cost method of accounting for oil and gas property acquisition,
exploration and development activities. Under this method, all productive and
non-productive costs incurred in connection with the acquisition of, exploration for and
development of oil and gas reserves for each cost center are capitalized. Capitalized
costs include lease acquisitions, geological and geophysical work, day rate rentals and
the costs of drilling, completing and equipping oil and gas wells. Costs, however,
associated with production and general corporate activities are expensed in the period
incurred. Interest costs related to unproved properties and properties under development
are also capitalized to oil and gas properties. Gains or losses are recognized only upon
sales or dispositions of significant amounts of oil and gas reserves representing an
entire cost center. Proceeds from all other sales or dispositions are treated as
reductions to capitalized costs. The capitalized oil and gas property, less accumulated
depreciation, depletion and amortization and related deferred income taxes, if any, are
generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the
present value of estimated future net revenues computed by applying current prices in
effect as of the balance sheet date (with consideration of price changes only to the
extent provided by contractual arrangements) to estimated future production of proved oil
and gas reserves, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the reserves using a discount factor of 10% and
assuming continuation of existing economic conditions; and (b) the cost of investments in
unevaluated properties excluded from the costs being amortized. No ceiling write-downs
were recorded in 2005, 2004 or 2003.

# 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 has no undeveloped, unproved properties and consequently, no such
properties have been excluded from the full cost pool.

41

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The
Companys proved oil and gas reserves as of December 31, 2005 were determined by
Ryder Scott, L.P., Petroleum Consultants. Projecting the effects of commodity prices on
production, and timing of development expenditures include many factors beyond the
Companys control. The future estimates of net cash flows from the Companys
proved reserves and their present value are based upon various assumptions about future
production levels, prices, and costs that may prove to be incorrect over time. Any
significant variance from assumptions could result in the actual future net cash flows
being materially different from the estimates.

# Asset Retirement
Obligations

The
Company is required to record the effects of contractual or other legal obligations on
well abandonments for capping and plugging wells. Management periodically reviews the
estimate of the timing of the wells closure as well as the estimated closing costs,
discounted at the credit adjusted risk free rate of 12%. Quarterly, management accretes
the 12% discount into the liability and makes other adjustments to the liability for well
retirements incurred during the period.

Recent
Accounting Pronouncements

In
December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 153,
Exchange of Non-monetary Assets. This statement is based on the principle that
exchanges of non-monetary assets should be measured based on the fair value of the assets
exchanged. SFAS 153 is effective for non monetary asset exchanges occurring in fiscal
periods beginning after June 15, 2005. The Company does not expect that the adoption of
SFAS No. 153 will have an impact on the Companys financial statements.

In
December 2004, the FASB published Statement of Financial Accounting Standards (SFAS) No.
123 (revised 2004), (SFAS 123(R)) Share Based Payment. SFAS 123(R) establishes
standards for the accounting for transactions in which an entity exchanges its equity
instruments for goods or services. SFAS 123(R) eliminates the ability to account for
share-based compensation transactions using APB Opinion No. 25 (APB 25), Accounting
for Stock Issued to Employees, and generally requires that such transactions be
accounted for using a fair-value-based method. This statement is effective for fiscal
years beginning after June 15, 2005. SFAS 123(R) applies to all awards granted after the
required effective date and to awards modified, repurchased, or cancelled after that date
and as a consequence future employee stock option grants and other stock based
compensation plans will be recorded as expense over the vesting period of the award based
on their fair values at the date the stock based compensation is granted. The cumulative
effect of initially applying SFAS 123(R) is to be recognized as of the required effective
date using a modified prospective method. Under the modified prospective method the
Company will recognize stock-based compensation expense from July 1, 2005 as if the fair
value based accounting method had been used to account for all outstanding unvested

42

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employee awards granted, modified or settled in prior years. The Company adopted SFAS
123(R) in 2005 and recognized $84,030 in compensation expense for options granted in 2005.
The Company will recognize $112,040 in 2006 and 2007 in compensation expense relating to
these options granted in 2005. The ultimate impact on future years results of operation
and financial position will depend upon the level of stock based compensation granted in
future years.

In
March 2005, the FASB issued Interpretation (FIN) No. 47, Accounting for Conditional
Asset Retirement Obligations- An Interpretation of SFAS No. 143", which clarifies the
term conditional asset retirement obligation used in SFAS No. 143,
Accounting for Asset Retirement Obligations, and specifically when an entity
would have sufficient information to reasonably estimate the fair value of an asset
retirement obligation. The adoption did not have an impact on the Companys financial
statements.

In
May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Correction
 a replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement
changes the requirements for the accounting for and reporting of a change in accounting
principle and applies to all voluntary changes in accounting principle. It also applies to
changes required by an accounting pronouncement in the unusual instance that the
pronouncement does not include specific transition provisions. When a pronouncement
includes specific transition provisions, those provisions should be followed. APB No. 20
required that most voluntary changes in accounting principle be recognized by including in
net income of the period of the change the cumulative effect of changing to the new
accounting principle. This statement requires retrospective application to prior period
financial statements of changes in accounting principle, unless it is impracticable to
determine either the period-specific effects or the cumulative effect of the change. The
provisions of SFAS No. 154 are effective for fiscal years beginning after December 15,
2005. The Company does not expect that the adoption of SFAS No. 154 will have an impact on
the Companys financial statements.

43

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# CONTRACTUAL OBLIGATIONS

The
following table summarizes the Companys contractual obligations at December 31,
2005:

|                                |  | Payments Due By Period |  
|------------------------------- |  | ---------------------- | -
|
|Long-Term Debt Obligations(11)  |  |                        | $
|Capital Lease Obligations       |  |                        | $
|Operating Lease Obligations(12) |  |                        | $
|Purchase Obligations            |  |                        | $
|Other Long-Term Liabilities(13) |  |                        | $
|Total                           |  |                        | $

# 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

44

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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
$40.73 per barrel to a high of $64.00 per barrel during 2005. Gas price realizations
ranged from a monthly low of $5.02 per Mcf to a monthly high of $14.03 per Mcf during the
same period. The Company did not enter into any hedging agreements in 2005 to limit
exposure to oil and gas price fluctuations.

# Interest Rate Risk

At
December 31, 2005, the Company had debt outstanding of approximately $176,779 at a fixed
rate. The Company did not have any open derivative contracts relating to interest rates at
December 31, 2005.

# Forward-Looking
Statements And Risk

Certain
statements in this report, including statements of the future plans, objectives, and
expected performance of the Company, are forward-looking statements that are dependent
upon certain events, risks and uncertainties that may be outside the Companys
control, and which could cause actual results to differ materially from those anticipated.
Some of these include, but are not limited to, the market prices of oil and gas, economic
and competitive conditions, inflation rates, legislative and regulatory changes, financial
market conditions, political and economic uncertainties of foreign governments, future
business decisions, and other uncertainties, all of which are difficult to predict.

There
are numerous uncertainties inherent in projecting future rates of production and the
timing of development expenditures. The total amount or timing of actual future production
may vary significantly from estimates. The drilling of exploratory wells can involve
significant risks, including those related to timing, success rates and cost overruns.
Lease and rig availability, complex geology and other factors can also affect these risks.
Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may
substantially adversely affect the Companys financial position, results of
operations and cash flows.

# ITEM 8      FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA

The
financial statements and supplementary data commence on page F-1.

# ITEM 9       CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON          ACCOUNTING AND FINANCIAL DISCLOSURE

On
May 31, 2005, the Company engaged Rodefer Moss & Co, PLLC (Rodefer Moss)
of Knoxville, Tennessee to serve as its independent registered public accounting firm and
dismissed BDO Seidman LLP (BDO). The change in independent registered public
accounting

45

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firms was approved by the Audit Committee of the Companys Board of
Directors and reported on a Current Report on Form 8-K, dated June 6, 2005. BDO audited
the Companys financial statements for the year ended December 31, 2004 and for
several prior years, and Rodefer Moss has audited the financial statements for the year
ended December 31, 2005.

# (a) Previous
Independent Auditors

BDOs
audit report on the financial statements for the year ended December 31, 2004 was
qualified for an uncertainty as to the Companys ability to continue as a going
concern. BDOs audit report for that period contained no adverse opinion or
disclaimer of opinion and was not qualified or modified as to audit scope or accounting
principles.

During
the fiscal year ended December 31, 2004 and the subsequent interim period through May 31,
2005, there were no disagreements with BDO on any matter of accounting principle or
practice, financial statement disclosure, or auditing scope or procedure which, if not
resolved to BDOs satisfaction, would have caused it to make reference to the subject
matter of the disagreement in connection with its reports.

None
of the reportable events set forth in Item 304(a)(1)(v) of Regulation S-K occurred within
the year ended December 31, 2004 or within the period from January 1, 2005 through May 31,
2005 except, that on November 12, 2004, BDO advised management and the Audit Committee
that it believed a material weakness existed in the Companys internal controls over
financial reporting. The Company disclosed this material weakness in the Companys
Quarterly Report on Form 10-Q for the quarter ending September 30, 2004 and in its Annual
Report on Form 10-K for the year ended December 31, 2004. The Company reported that its
disclosure controls and procedures were not effective to ensure that material information
was recorded, processed, summarized and reported by management of the Company on a timely
basis in order to comply with the Companys disclosure obligations under the
Securities Exchange Act of 1934, and the rules and regulations thereunder as to one
particular matter. That matter involved an error in the calculation of the estimated fair
value of the Companys mandatory preferred stock for presentation in accordance with
Statement of Financial Accounting Standard No. 150 Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. Management noted
that the matter (i) related principally to the implementation of complex and new
calculations under a newly implemented accounting standard, and (ii) that the error
described did not result from the failure of the Companys disclosure controls and
procedures to make known to the appropriate officials and auditors the facts concerning
the Companys convertible preferred stock. Management after consulting with BDO
determined that this could be remedied by continuing education and professional
development of accounting staff on new accounting pronouncements and this would be
sufficient to prevent any similar reoccurrence. The Company has and is continuing to
provide necessary and appropriate educational and professional development and such
efforts have remediated the material weakness described herein.

46

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The
Company previously provided BDO with a copy of the foregoing statements set forth in the
8-K Report referred to above and requested that BDO furnish it with a letter addressed to
the SEC stating whether or not it agreed with such statements. BDO has provided the
Company with a copy of the letter it sent to the SEC stating that it had reviewed the
disclosure provided in the 8-K Report and it agreed with the statements in that Report
regarding BDO.

# (b) New Independent
Accountants

Prior
to engaging Rodefer Moss as its new independent auditors, the Company did not consult with
Rodefer Moss regarding (i) the application of accounting principles to a specified
transaction, either completed or proposed; (ii) the type of audit opinion that might be
rendered by Rodefer Moss on the Companys financial statements; or (iii) any other
matter that was the subject of a disagreement between the Company and its former auditors
as described in Item 304(a)(1)(iv) of Regulation S-K or a reportable event as that term is
defined in Item 304(a)(1)(v).

# ITEM 9A CONTROLS AND
PROCEDURES

# Evaluation of Disclosure
Controls and Procedures

The
Companys Chief Executive Officer and Principal Financial Officer, and other members
of management team have evaluated the effectiveness of the Companys disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based
on such evaluation, the Companys Chief Executive Officer and Principal Financial
Officer have concluded that the Companys disclosure controls and procedures, as of
the end of the period covered by this Report, were adequate and effective to provide
reasonable assurance that information required to be disclosed by the Company in reports
that it files or submits under the Exchange Act, is recorded, processed, summarized and
reported, within the time periods specified in the SECs rules and forms.

The
effectiveness of a system of disclosure controls and procedures is subject to various
inherent limitations, including cost limitations, judgments used in decision making,
assumptions about the likelihood of future events, the soundness of internal controls, and
fraud. Due to such inherent limitations, there can be no assurance that any system of
disclosure controls and procedures will be successful in preventing all errors or fraud,
or in making all material information known in a timely manner to the appropriate levels
of management.

47

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# Changes in Internal
Controls

There
have been no changes to the Companys system of internal control over financial
reporting during the quarter ended December 31, 2005 that has materially affected, or is
reasonably likely to materially affect, the Companys system of controls over
financial reporting.

As
part of a continuing effort to improve the Companys business processes management is
evaluating its internal controls and may update certain controls to accommodate any
modifications to its business processes or accounting procedures.

# ITEM 9B      OTHER INFORMATION

None.

# PART III

Certain
information required by Part III of this Report is incorporated by reference from the
Companys definitive proxy statement to be filed with the SEC in connection with the
solicitation of proxies for the Companys 2006 Annual Meeting of Stockholders (the
Proxy Statement).

# ITEM 10       DIRECTORS AND
EXECUTIVE OFFICERS OF THE REGISTRANT

The
information required by this Item with respect to the Companys directors is
incorporated by reference to the information in the section entitled Proposal No. 1:
Election of Directors in the Proxy Statement.

The
information required by this Item with respect to the Audit Committee and other committees
of the Board of Directors is incorporated by reference from the section entitled
Board of Directors  Committees in the Proxy Statement.

The
information required by this Item with respect to disclosure of any known late filing or
failure by an insider to file a report required by Section 16 of the Exchange Act is
incorporated by reference to the information in the section entitled Section 16(a)
Beneficial Ownership Reporting Compliance in the Proxy Statement.

The
information required by this Item with respect to the identification and background of the
Companys executive officers and the Companys code of ethics is set forth in
Item 1 of this Report.

48

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# ITEM 11        EXECUTIVE
COMPENSATION

The
information required by this Item is incorporated by reference from the information in the
sections entitled Executive Compensation and Compensation/Stock Option
Committee Interlocking and Insider Participation in the Proxy Statement.

# ITEM 12        SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The
information required by this Item regarding security ownership of certain beneficial
owners and directors and officers is incorporated by reference from the sections entitled
Voting Securities and Principal Holders and Beneficial Ownership of
Directors and Officers in the Proxy Statement. Information required by this Item
regarding securities authorized for issuance under equity compensation plans is set forth
in Item 5 of this Report.

# ITEM 13        CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS

Information
required by this Item is incorporated by reference from the section entitled Certain
Transactions in the Proxy Statement.

# ITEM 14        PRINCIPAL
ACCOUNTANTS FEES AND SERVICES

The
information required by this Item is incorporated by reference from the information in the
section entitled Proposal No. 2: Ratification of Selection of Rodefer Moss & Co,
PLLC as Independent Auditors in the Proxy Statement.

49

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# PART IV

# ITEM 15 EXHIBITS and
FINANCIAL STATEMENT SCHEDULES

A.    
          The following documents are filed as part of this Report:

1.    
          Financial Statements:

|                                                | 
|----------------------------------------------- | 
|Consolidated Balance Sheets                     | 
|Consolidated Statements of Loss                 | 
|Consolidated Statements of Stockholders' Equity | 
|Consolidated Statements of Cash Flows           | 
|Notes to Consolidated Financial Statements      | 

2.    
          Financial Schedules:

Schedules
have been omitted because the information required to be set forth therein is not
applicable or is included in the Consolidated Financial Statements or notes thereto. 3.
Exhibits.

The
following exhibits are filed with, or incorporated by reference into this Report:                                      Exhibit Index

|               |            
|-------------- | -----------
|Exhibit
Number | Description
|               |            

| | 3.1 | Charter(Incorporated by reference to Exhibit 3.7 to the registrants registration statement
 on Form 10-SB filed August 7, 1997 (the Form 10-SB))
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.2 | Articles of Merger and Plan of Merger (taking into account the formation of the
Tennessee wholly-owned subsidiary for the purpose of changing the Companys domicile and
effecting reverse split) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.3 | Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to
Exhibit 3.9 to the registrants annual report on Form 10-KSB filed April 15, 1999
(the 1998 Form 10-KSB))
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.4 | Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by
                            reference to Exhibit 3.10 to the 1998 Form 10-KSB)
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.5 | Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to
Exhibit 3.11 to the registrants annual report on Form 10-KSB filed April 14, 2000
(the 1999 Form 10-KSB))
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 3.6 | By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
| | --- | --------------------------------------------------------------------

| | 3.7* | Amendment and Restated By-laws dated May 19, 2005 By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
| | ---- | ----------------------------------------------------------------------------------------------------------------------

| | 4.1 | Form of Rights Certificate Incorporated by reference to registrant's statement on
Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the Form S-1)
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.1 | Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and
                            Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the
                            registrant's current report on Form 8-K filed November 23, 1999)
| | ---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.2 | Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March
                            27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant's 1999 Form
                            10-KSB)
| | ---- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.3 | Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems
                            Inc. dated March 30, 2001 (Incorporated by reference to Exhibit 10.20 to the 2000
                            Form 10-KSB)
| | ---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

50

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| | 10.4 | Reducing and Revolving Line of Credit Up to $35,000,000 from Bank One, N.A.  to
                            Tengasco, Inc. Tennessee Land & Mineral Corporation and Tengasco Pipeline
                            Corporation dated November 8, 2001 (Incorporated by reference to Exhibit 10.21 to
                            the registrant's quarterly report on Form 10-Q filed November 14, 2001)
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.5 | Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to
                            the registrant's registration statement on Form S-8 filed October 26, 2000)
| | ---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.6 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated October 7, 2002 in the principal amount of $500,000
                            (Incorporated by reference to Exhibit 10.35 to the Form S-1)
| | ---- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.7 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated December 4, 2002 in the principal amount of $250,000
                            (Incorporated by reference to Exhibit 10.36 to the Form S-1)
| | ---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.8 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated February 3, 2003 in the principal amount of $250,000
                            (Incorporated by reference to Exhibit 10.37 to the Form S-1)
| | ---- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.9 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated February 28, 2003 in the principal amount of $250,000
                            (Incorporated by reference to Exhibit 10.38 to the Form S-1)
| | ---- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.10 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated May 20, 2003 in the principal amount of $750,000
                            (Incorporated by reference to Exhibit 10.39 to the Form S-1)
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.11 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated August 6, 2003 in the principal amount of $150,000
                            (Incorporated by reference to Exhibit 10.40 to the Form S-1)
| | ----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.12 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Jeffrey
                            R. Bailey dated May 20, 2003 in the principal amount of $84,000 (Incorporated by reference
to Exhibit 10.41 to the Form S-1)
| | ----- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.13 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
Offshore Partners, LP dated December 3, 2003 in the principal amount of $225,000
(Incorporated by reference to Exhibit 10.42 to the registrants current report on
Form 8-K dated December 3, 2003 (the 2003 Form 8-K)
| | ----- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.14 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
Offshore Partners, LP dated December 9, 2003 in the principal amount of $250,000
(Incorporated by reference to Exhibit 10.43 to the 2003 Form 8-K)
| | ----- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.15 | Continuing Security Agreement dated December 3, 2003 by the Company and Tengasco Pipeline
Corporation as Obligors and Dolphin Offshore Partners, LP as Secured Party (Incorporated
by reference to Exhibit 10.44 to the 2003 Form 8-K)
| | ----- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.16 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
                            Offshore Partners, LP dated December 24, 2003 in the principal amount of $1,000,000
                            (Incorporated by reference to Exhibit 10.45 to the Form S-1)
| | ----- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.17 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Jeffrey
                            R. Bailey dated February 2, 2004 in the principal amount of $225,000 (Incorporated by reference to Exhibit 10.46 to the Form S-1)
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.18 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
Offshore Partners, LP dated May 18, 2004 in the principal amount of $2,500,000
(Incorporated by reference to Exhibit 10.47 to the registrants quarterly report on
Form 10-Q filed May 20, 2004)
| | ----- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.19 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
Offshore Partners, LP dated December 30, 2004 in the principal amount of $550,000
(Incorporated by reference from to Exhibit 10.19 to the registrants Annual Report on
Form 10-K filed March 31, 2005)
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

51

---



| | 10.20 | Asset Purchase Agreement dated March 4, 2005 between Tengasco, Inc. and Bear
                            Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 the registrant's current
                            report on Form 8-K dated March 9, 2005 (the "March 9, 2005 Form 8-K")
| | ----- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.21 | Assignment and Bill of Sale between Tengasco, Inc. and Bear Petroleum, Inc.
                            (Incorporated by reference to Exhibit 10.2 to the March 9, 2005 Form 8-K)
| | ----- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.22 | Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline
Corporation to Dolphin Offshore Partners, LP dated May 19, 2005 in the principal amount of
$700,000 ((Incorporated by reference to Exhibit 10.1 to the registrants current
report on Form 8-K dated May 23, 2005)
| | ----- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.23 | Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin
Offshore Partners, LP dated August 22, 2005 in the principal amount of $1,814,000
(Incorporated by reference to Exhibit 10.1 to the registrants current report on Form
8-K dated August 22, 2005 (the August 22, 2005 8-K))
| | ----- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.24 | Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline
Corporation dated August 18, 2005 in the principal amount of $700,000 (Incorporated by
reference to Exhibit 10.2 to the August 22, 2005 8-K.)
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 10.25 | Subscription Agreement of Hoactzin Partners, L.P. for a 94.275% working interest in the
Companys twelve well drilling program on its Kansas Properties. (Incorporated by
reference to Exhibit 10.1 to the registrants current report on Form 8-K dated
October 5, 2005)
| | ----- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 14 | Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant's annual
                            report on Form 10-K filed March 30, 2004)
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------

| | 16.1 | Letter from BDO Seidman LLP (BDO) to the Securities and Exchange Commission
dated June 3, 2005 agreeing to statements made as to BDO in current report on Form 8-K as
to registrants change of independent auditors. (Incorporated by reference to Exhibit
16.1to registrants current report on Form 8-K dated June 6, 2005.)
| | ---- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 21 | List of subsidiaries (Incorporated by reference to Exhibit 21 to the registrants
annual report on Form 10-K filed March 31, 2003 (the 2002 Form 10-KSB))
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------

| | 23.1* | Consent of Ryder Scott Company, L.P.
| | ----- | ------------------------------------

| | 23.2* | Consent of BDO Seidman, LLP
| | ----- | ---------------------------

| | 31.1* | Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
| | ----- | -----------------------------------------------------------------------------

| | 31.2* | Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
| | ----- | -----------------------------------------------------------------------------

| | 32.1* | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as
                            adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| | ----- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | 32.2* | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as
                            adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| | ----- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

* Exhibit filed with this Report

52

---



# 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 20, 2006

TENGASCO, INC.(Registrant)

|                                                                                                                                          | 
|----------------------------------------------------------------------------------------------------------------------------------------- | 
|                                                                                                                                          | 
|By: s/Jeffrey R. BaileyJeffrey R. Bailey,Chief Executive OfficerBy: s/Mark A. RuthMark 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/Clarke H. Bailey   |  |  | Director               
|Clarke H. Bailey     |  | 
|s/Jeffrey R. Bailey  |  |  | Director;              
|Jeffrey R. Bailey    |  |  | Chief Executive Officer
|s/John A. Clendening |  |  | Director               
|John A. Clendening   |  | 
|s/Neal F. Harding    |  |  | Director               
|Neal F. Harding      |  | 
|s/Carlos P. Salas    |  |  | Director               
|Carlos P. Salas      |  | 
|s/Peter E. Salas     |  |  | Director;              
|Peter E. Salas       |  |  | Chairman               
|s/Mark A. Ruth       |  |  | Principal Financial    
|Mark A. Ruth         |  |  | and Accounting Officer 

53

---



(1)       
          Mr. Bailey is also a director of the Company.

(2)       
          The background and business experience of Jeffrey R. Bailey is incorporated by
          reference from the section entitled Proposal No. 1: Election of
          Directors in the Companys Proxy Statement for the Company 2006
          Annual Meeting of Stockholders.

(3)       
          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.

| | (4)       
               Although the actual total cost of production for the Swan Creek Field in 2005 as
               compared to 2004 remained relatively constant, the cost per BOE increased
               because of the decrease in production volumes of oil and gas.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (5) Although the actual total cost of production for the Swan Creek Field
               in 2004 as compared to 200 remained constant, the cost per BOE increased
               substantially because of a decrease in production volumes of oil and gas.
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (6)       
               Reflects the fact that the Company sold all of the gas producing wells on its
               Kansas Properties on March 4, 2005 effective as of February 1, 2005. Thus, gas
               production is only for January 2005.
| | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (7)       
               Refers to Tengasco, Inc. Stock Incentive Plan (the Plan) which was
               adopted to provide an incentive to key employees, officers, directors and
               consultants of the Company and its present and future subsidiary corporations,
               and to offer an additional inducement in obtaining the services of such
               individuals. The Plan provides for the grant to employees of the Company of
               Incentive Stock Options, within the meaning of Section 422 of the
               Internal Revenue Code of 1986, as amended, Nonqualified Stock Options to outside
               Directors and consultants to the Company and stock appreciation rights. The plan
               was approved by the Companys shareholders on June 26, 2001. Initially, the
               Plan provided for the issuance of a maximum of 1,000,000 shares of the
               Companys $.001 par value common stock. Thereafter, the Companys
               Board of Directors adopted and the shareholders approved an amendment to the
               Plan to increase the aggregate number of shares that may be issued under the
               Plan from 1,000,000 shares to 3,500,000 shares.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (8)       
               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.
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (9)       
               No cash dividends have been declared or paid by the Company for the periods
               presented.
| | -------------------------------------------------------------------------------------------------------------------------------

| | (10)       
               On July 1, 2003, the Company adopted the provisions of Statement of Financial
               Accounting Standards No. 150 under which mandatorily redeemable preferred stock
               shall be reclassified at estimated fair value to a liability. Thus, in 2003, it
               was determined that each of the Companys series of preferred stock
               qualifies as shares subject to mandatory redemption and should be classified as
               a liability.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (11)       
               See, Note 7 to Consolidated Financial Statements in Item 8 of this Report.
| | -----------------------------------------------------------------------------------------------------

| | (12)       
               See, Note 8 to Consolidated Financial Statements in Item 8 of this Report.
| | -----------------------------------------------------------------------------------------------------

| | (13)       
               Represents obligations for 11 wells that remain to be drilled in the
               Companys Eight and Twelve Well Programs in Kansas. See, Item 2
               Properties  Oil and Gas Drilling Activities. Although these
               obligations have been included in the category of Less than 1 year,
               the Twelve Well Program contains no time period in which the wells must be
               drilled. The Company anticipates, however, that the remaining wells in this
               Program will be drilled in one year. See also, Note 9 to Consolidated Financial
               Statements in Item 8 of this Report.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



---



Tengasco, Inc.and Subsidiaries       Consolidated Financial Statements Years Ended December 31, 2005, 2004 and 2003                   Report of Independent Registered Public Accounting Firm
        F-3Consolidated Financial StatementsConsolidated Balance Sheets
        F-4 F-5Consolidated Statements of Operations
        F-6Consolidated Statements of  Stockholders Equity                                       F-7Consolidated Statements of Cash Flows
        F-8 F-9Notes to Consolidated Financial Statements
        F-10  F-32   F-2        REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  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, 2005 and the related consolidated statements of operations, stockholders' equity and cash flows for the year then ended. 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 audit.  We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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, 2005 and the results of their operations and cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.   /s/ Rodefer Moss & Co, PLLC  Knoxville, Tennessee March 1, 2006       F-3     REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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, 2004 and 2003, and the related consolidated statements of loss, stockholders' equity and comprehensive loss and cash flows for each of the three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companys internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, 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 consolidated financial statements, the Company has suffered recurring losses from operations and, at December 31, 2004, has an accumulated deficit of $33,385,524 and a working capital deficit of $6,753,721.  The working capital deficiency has resulted in the Company's inability to pay cumulative dividends and mandatory redemption requirements on the Company's shares subject to mandatory redemption.  Such matters raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.  As discussed in Notes 9 & 10 to the consolidated financial statements, the Company implemented the provisions of Statement of Financial Accounting Series No. 143, "Asset Retirement Obligations" on January 1, 2003 and the provisions of Statement of Financial Accounting Series No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" on July 1, 2003. /s/ BDO Seidman, LLP Atlanta, Georgia March 21, 2005            Tengasco, Inc. and Subsidiaries Consolidated Balance Sheet     December 31,
        2005
        2004Assets(Note 1)CurrentCash and cash equivalents
        $260,969
        $      267,735Accounts receivable
        1,154,405
        706,752Participant receivables
        9,777
        73,016Inventory
        496,331
        341,745Other current assets
        6,056
        67,526Total current assets
        1,927,538
        1,456,774Oil and gas properties,net (on the basis
of full cost accounting) (Notes 4 and 18)
        9,675,877
        12,826,903Pipeline facilities,netof accumulated
depreciation of $ 2,335,099 and $1,812,204 (Note 5)
        13,994,453
        14,602,639Other property and equipment, net (Note 6 )
        310,748
        323,433$25,908,616
        $     29,209,749 See accompanying Notes to Consolidated Financial Statements   F-4     Tengasco, Inc. and Subsidiaries Consolidated Balance Sheet     December 31,
        2005
        2004Liabilities and Stockholders Equity(Note 1)Current liabilitiesCurrent maturities of long-term debt (Note  7)
        $58,867
        $      26,672Accounts payable
        597,278
        319,820Accrued interest payable
        -
        25,367Other accrued liabilities
        281,737
        211,622Notes payable to related parties (Note 2)
        -
        3,050,000Drilling program (Note 9)
        2,324,400
        1,316,702Current shares subject to mandatory redemption (Note 9)
        -
        3,260,312Total current liabilities
        3,262,282
        8,210,495Shares subject to mandatory redemption(Note 9)
        -
        1,395,301Drilling program(Note 9)
        -
        438,901Asset retirement obligations(Note 10)
        566,968
        708,677Long term debt,less currentmaturities(Note 7)
        117,912
        106,688Total liabilities
        3,947,162
        10,860,062Commitments and Contingencies(Notes 5, 7, 8, and 10)Stockholders equity(Note 11)Common stock, $.001 par value; authorized 100,000,000 shares;
58,604,678 and 48,927,828 shares issued and outstanding
        58,605
        48,928Additional paid-in capital
        54,200,345
        51,686,283Accumulated deficit
        (32,297,496)
        (33,385,524)Total Stockholders equity
        21,961,454
        18,349,687$25,908,616
        $      29,209,749 See accompanying Notes to Consolidated Financial Statements  F-5     Tengasco, Inc. and Subsidiaries Consolidated Statement of Operations     Years ended December 31,
        2005
        2004
        2003Revenues and other incomeOil and gas revenues
        $     7,076,790
        $     6,013,374
        $     6,040,872Pipeline transportation revenues
        94,911
        92,599
        163,393Interest Income
        1,175
        3,501
        985Total revenues and other income
        7,172,876
        6,109,474
        6,205,250Costs and expensesProduction costs and taxes
        3,046,460
        3,364,429
        3,412,201Depreciation, depletion and amortization
Notes 4, 5 and 6)
        1,605,043
        2,067,566
        2,308,007General and administrative
        1,322,616
        1,177,183
        1,486,280Interest expense (Notes 9, 10 and 13)
        472,655
        1,367,180
        1,120,738Public relations
        30,020
        35,347
        31,183Professional fees
        263,800
        779,180
        549,503Loss on impairment of long-lived asset
        -
        -
        495,000Loss on sale of equipment, net
        -
        107,744
        -Total costs and expenses
        6,740,594
        8,898,629
        9,402,912Net Operating Income/Loss
        432,282
        (2,789,155)
        (3,197,662)Gain from extinguishment of debt (Note 16)
        -
        336,820
        -Gain on Preferred Stock (Note 9)
        655,746
        458,310
        -Net income/loss before
Cumulative effects of a changes in accounting principle
        $     1,088,028
        $     (1,994,025)
        $     (3,197,662)Cumulative effect of a change in accounting principle (Note 10)
        -
        -
        (351,204)Cumulative effect of a change in accounting principle (Note 9)
        -
        -
        365,675Net Income/Loss
        $     1,088,028
        $     (1,994,025)
        $     (3,183,191)Dividends on preferred stock (Note 9)
        -
        -
        (268,389)Net Income/Loss attributable to common stockholders
        $     1,088,028
        $     (1,994,025)
        $     (3,451,580)Net Income/Loss attributable to common stockholders per shares
Basic and diluted:Operations
        $       0.02
        $       (0.05)
        $(0.29)Cumulative effect of a change in accounting principle (Note 10)
        -
        -
        (0.03)Cumulative effect of a change in accounting principle (Note 9)
        -
        -
        0.03Total
        $     0.02
        $     (0.05)
        $   (0.29)Weighted average shares outstanding
        52,019,051
        40,855,972
        11,956,135 See accompanying Notes to Consolidated Financial Statements  F-6     Tengasco, Inc. and Subsidiaries Consolidated Statement of Stockholders Equity     Common Stock
        
        Paid-InCapital
        
        AccumulatedDeficit
        
        ComprehensiveLoss
        
        AccumulatedOtherComprehensiveIncome (Loss)
        
        Treasury StockShares
        
        Amount
        
        TotalShares
        
        AmountBalance,December 31, 2002
        11,630,130
        
        
        11,631
        
        
        42,237,105
        
        
        (27,776,726
        )
        
        
        
        
        (115,500
        )
        14,500
        
        
        (145,887
        )
        
        14,210,623Net loss
        
        
        
        
        
        
        
        
        
        (3,197,662
        )
        
        
        
        
        
        
        
        
        
        
        
        
        (3,197,662)Cumulative effects of changes in accountingprinciples
        
        
        
        
        
        
        
        
        
        14,471
        
        
        
        
        
        
        
        
        
        
        
        
        
        14,471Comprehensive loss:Net loss
        
        
        
        
        
        
        
        
        
        
        
        
        (3,197,662
        )
        
        
        
        
        
        
        
        
        
        Other comprehensive gain
        
        
        
        
        
        
        
        
        
        
        
        
        25,500
        
        
        25,500
        
        
        
        
        
        
        
        25,5002003 comprehensive loss
        
        
        
        
        
        
        
        
        
        
        
        
        (3,172,162
        )
        
        
        
        
        
        
        
        
        
        Common stock issued in private placements,net of related expenses
        227,275
        
        
        227
        
        
        249,773
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        250,000Common stock issued on conversion of debt
        60,528
        
        
        61
        
        
        69,538
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        69,599Common stock issued for charity
        3,571
        
        
        4
        
        
        5,710
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        5,714Common stock issued for services
        55,500
        
        
        70
        
        
        (64,458
        )
        
        
        
        
        
        
        
        
        
        (14,500
        )
        
        145,887
        
        
        81,499Common stock issued for exercised in arrearsoptions
        94,000
        
        
        94
        
        
        46,906
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        47,000Common stock issued for preferreddividends in arrears
        154,824
        
        
        154
        
        
        170,155
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        170,309Common stock issued for litigationsettlement
        10,000
        
        
        10
        
        
        6,390
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        6,400Accretion of issue cost on preferred stock-series B & C
        
        
        
        
        
        
        
        
        
        (163,193
        )
        
        
        
        
        
        
        
        
        
        
        
        
        (163,193)Dividends on convertible redeemablepreferred stock
        
        
        
        
        
        
        
        
        
        (268,389
        )
        
        
        
        
        
        
        
        
        
        
        
        
        (268,389)Balance,December 31, 2003
        12,235,828
        
        
        12,251
        
        
        42,721,119
        
        
        (31,391,499
        )
        
        
        
        
        (90,000
        )
        
        
        
        
        
        
        11,251,871Net Loss
        
        
        
        
        
        
        
        
        
        (1,994,025
        )
        
        
        
        
        
        
        
        
        
        
        
        
        (1,994,025)Common stock issued for exercised options
        142,000
        
        
        142
        
        
        70,858
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        71,000Common stock issued in Rights Offering
        36,300,000
        
        
        36,285
        
        
        8,812,056
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        8,848,341Common stock issued for services
        250,000
        
        
        250
        
        
        82,250
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        82,500Transfer of investment (Note 15)
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        90,000
        
        
        
        
        
        
        
        90,000Balance,December 31, 2004
        48,927,828
        
        
        48,928
        
        
        51,686,283
        
        
        (33,385,524
        )
        
        
        
        
        
        
        
        
        
        
        
        
        18,349,687Net Income
        
        
        
        
        
        
        
        
        
        1,088,028
        
        
        
        
        
        
        
        
        
        
        
        
        
        1,088,028Common Stock issued for exercised options
        100,000
        
        
        100
        
        
        26,900
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        27,000Options Expense
        
        
        
        
        
        
        84,030
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        84,030Lawsuit Settlement
        4,000
        
        
        4
        
        
        19,366
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        19,370Conversion of Stock
        9,567,620
        
        
        9,568
        
        
        2,381,418
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        2,390,986Common Stock issued for exercise of
Warrants
        5,230
        
        
        5
        
        
        2,348
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        
        2,353Balance,December 31, 2005
        58,604,678
        
        
        58,605
        
        
        54,200,345
        
        
        (32,297,496
        )
        
        
        
        
        
        
        
        
        
        
        
        
        21,961,454 See accompanying Notes to Consolidated Financial Statements  F-7     Tengasco, Inc. and Subsidiaries Consolidated Statement of Cash Flows     Years ended December 31,
        2005
        2004
        2003Operating activitiesNet Income/Loss
        $1,088,028
        $  (1,994,025)
        $  (3,197,662)Adjustments to reconcile Net Income/Loss to net cash
rovided by (used in) operating activities:Depreciation, depletion and amortization
        1,605,043
        2,067,566
        2,308,007Compensation and services paid in stock options, stock
arrants, and common stock
        103,400
        82,500
        203,812Loss on impairment of long-lived assets
        -
        -
        495,000Accretions of redeemable shares and A.R.O., net
        233,696
        792,124
        459,691Gain of extinguishment of Asset Retirement Obligation
        (72,399)
        -
        -Gain on sale of pipeline facilities
        (17,605)
        -
        -Loss (gain) on sale of equipment, net
        (15,330)
        99,456
        (13,103)Loan fee amortization
        -
        107,956
        -Gain on extinguishment of debt
        -
        (336,820)
        -Gain on exchange of preferred stock
        (655,746)
        (458,310)
        -Realized loss on investment
        -
        150,000
        -Changes in assets and liabilities:Accounts receivable
        (447,653)
        (198,374)
        222,289Participant receivables
        63,239
        (4,614)
        2,203Inventory
        (154,586)
        (61,052)
        (17,945)Other assets
        61,470
        155,477
        14,613Accounts payable  trade
        277,458
        (756,129)
        (320,813)Accrued interest payable
        (25,367)
        (208,954)
        173,179Other accrued liabilities
        70,115
        193,062
        (13,244)Net cash  (used in) provided by Operating activities
        2,113,763
        (370,137)
        316,027Investing activitiesAdditions to other property & equipment
        (210,145)
        (40,815)
        -Decreases to other property and equipment
        55,919
        296,865
        -Additions to oil and gas properties
        (2,348,078)
        (1,122,903)
        (133,501)Drilling Program portion of additional drilling
        1,945,202Decrease (additions) to pipeline facilities
        72,186
        (10,001)
        (5,775)Other
        -
        -
        74,207Sale of Kansas Properties
        2,651,770
        -
        -Net cash (used in) provided by Investing activities
        2,166,854
        (876,854)
        (65,069)Financing activitiesProceeds from exercise of options/warrants
        29,352
        71,000
        47,000Proceeds from borrowings
        155,073
        3,310,815
        3,256,171Repayments of borrowings
        (3,182,636)
        (9,848,560)
        (3,432,470)Proceeds from issuance of common stock
        2,391,905
        8,848,341
        250,000Dividends paid  on preferred stock
        (8,000)
        (456,166)
        (20,120)Repayments of Redeemable Liabilities
        (4,241,874)
        (723,370)
        -Payment of loan and offering fees
        -
        -
        (223,003)Repayment of Drilling Program
        (1,945,203)
        -
        -New Drilling Program
        2,514,000
        -
        -Net cash provided by (used in) Financing activities
        (4,287,383)
        1,202,060
        (122,422)Net change in cash and cash equivalents
        (6,766)
        (44,931)
        128,536Cash and cash equivalents, beginning of year
        $267,735
        $312,666
        $184,130    F-8     Tengasco, Inc. and Subsidiaries Consolidated Statement of Cash Flows    Cash and cash equivalents, end of year
        $260,969
        $   267,735
        $   312,666Supplemental disclosure of non-cash investing and
financing activities:Issuance of common stock on conversion of debt/preferred stock
        $2,391,905
        -
        $    69,549Issuance of common stock and stock options for services received                                                                        and charitable contributions made
        -
-
        -
        $   203,812Capitalization of lawsuit settlement relating to the pipeline
        -
        -
        $   297,171Capitalization of future asset retirement obligations to oil and gas                                                                                properties
        -
        -
        $   346,922Conversion of Series A  Preferred Stock into a drilling program
        -
        $   1,755,603
        $               - See accompanying Notes to Consolidated Financial Statements   F-9     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   (1.)
        Summary of Significant Accounting Policies  Organization  Tengasco, Inc. (the Company), a publicly held corporation, was organized under the laws of the State of Utah on April 18, 1916, as Gold Deposit Mining and Milling Company. The Company subsequently changed its name to Onasco Companies, Inc. The Company changed its domicile from the State of Utah to the State of Tennessee on May 5, 1995 and its name was changed from Onasco Companies, Inc. to Tengasco, Inc.  The Companys principal business consists of oil and gas exploration, production and related property management in Kansas and the Appalachian region of eastern Tennessee. 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 own and manage the construction and operation of a 65-mile gas pipeline as well as other pipelines planned for the future.  During 2001, TPC began transportation of natural gas through its pipeline to customers of Tengasco.  Basis of Presentation  The accompanying consolidated financial 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. Certain prior year amounts have been reclassified to conform with current year presentation.  The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation and Tennessee Land & Mineral Corporation.  All significant intercompany balances and transactions have been eliminated.  Use of Estimates  The accompanying consolidated 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   F-10     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Natural gas meters are placed at the customers locations and usage is billed monthly.  Cash and Cash Equivalents  The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.  Investment Securities  Investment securities available for sale are reported at fair value, with unrealized gains and losses reported as a separate component of stockholders equity, net of the related tax effects. The Companys available for sale securities were transferred as part of a lawsuit settlement in 2004. The Company recognized a realized loss of $150,000 as a result of the transfer. See Note 15.  Inventory  Inventory consists primarily of crude oil in tanks and is carried at market value.  Oil and Gas Properties  The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals and the costs of drilling, completing, equipping and plugging oil and gas wells.  Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center.  Proceeds from all other sales or dispositions are treated as reductions to capitalized costs.  The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company has no undeveloped unproved properties and consequently no such properties have been excluded from the full cost pool. These reserves were estimated by Ryder Scott Company, Petroleum Consultants in 2005, 2004, and 2003 .  The capitalized oil and gas properties, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded  F-11     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   from the costs being amortized. The Company has adopted an SEC accepted method of calculating the full cost ceiling test whereby the liability recognized under Statement of Financial Accounting Standard No. 143 (SFAS) Accounting for Asset Retirement Obligation (SFAS 143) is netted against property cost and the future abandonment obligations are included in estimated future net cash flows.No ceiling write-downs were recorded in 2005, 2004, or 2003.  Pipeline Facilities  Phase I of the pipeline was completed during 1999.  Phase II of the pipeline was completed on March 8, 2001.  Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years beginning at the time it was placed in service.  Other Property and Equipment and Long - Lived Assets  Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from three to seven years.  Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value.  At December 31, 2005, 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.  Stock-Based Compensation  SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123), was issued in January 1996. As permitted by SFAS 123, the Company had continued to account for stock compensation to employees by applying the provisions of Accounting Principles Board Opinion No. 25. If the accounting provisions of SFAS 123 had been adopted, net loss and loss per share would have been as follows for the years ended December 31, 2004, and 2003. The Company recorded $84,030 in compensation expense in 2005 upon the Companys adoption of SFAS 123 (R) in 2005.   2004
        
        2003Net loss attributable to common shareholdersAs reported
        
        $
        (1,994,025)
        
        $
        (3,451,580)Stock based compensation
        
        
        -
        
        
        (22,650)Pro forma
        
        $
        (1,994,025)
        
        $
        (3,474,230)Basic and diluted loss per shareAs reported
        
        $
        (0.05)
        
        $
        (0.29)Pro forma
        
        $
        (0.05)
        
        $
        (0.29)    F-12     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   Accounts Receivable  Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible.  Management includes any accounts receivable balances that are determined to be uncollectible, along with a general reserve, in the overall allowance for doubtful accounts. After all attempts to collect a receivable have failed, the receivable is written off against the allowance.  Based on the information available to us, the Company believes no allowance for doubtful accounts as of December 31, 2005 and 2004 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 carry-forwards.  Management evaluates the likelihood of realization for such assets at year-end providing a valuation allowance for any such amounts not likely to be recovered in future periods.  The Company currently has a net operating loss carry forward of $24,230,000.  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 Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry. The Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field, principally Eastman Chemical Company and other industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.  The Company has entered into contracts to supply two manufacturers with natural gas from the Swan Creek Field (Tennessee) through the Companys pipeline. These customers are the Companys primary customers for natural gas sales.  Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Companys projected results of operations.  F-13     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    In 2005, the Company received 74.6 percent of its revenues from Customer A; 18.6 percent of its revenues from Customer B.  In 2004, the Company received 59.3 percent of its revenues from Customer A; 18.2 percent of its revenues from Customer B; and 14.4 percent of its revenues from Customer C.  In 2003, the Company received 45.9 percent of its revenues from Customer A; 28.1 percent of its revenues from Customer B; and 15.7 percent of its revenues from Customer C.  In each of the years 2003 through 2005, the identity of the customers indicated above as either A or B was the same from year to year, although the percentage of revenues varied  from year to year for that customer. Customer C in 2004 and 2003 relates to the gas field in Kansas that was sold in February of 2005.  Income/Loss per Common Share  Basic income/loss per share is computed by dividing gain or 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. Basic and diluted income/loss per share are based upon 52,019,051 weighted average common shares outstanding for the year ended December 31, 2005; 40,855,972 weighted average common shares outstanding for the year ended December 31, 2004; and 11,956,135 weighted average common shares outstanding for the year ended December 31, 2003. Diluted loss per share does not consider approximately 390,278 potential weighted average common shares for 2003 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 in 2003 and, thus, any potential common shares were anti-dilutive to the loss per share calculation. The 2005 amount includes 640,000 potential weighted average common shares relating to common stock options.  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 December 2004, the FASB issued SFAS No. 153, Exchange of Non-monetary Assets. This statement is based on the principle that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanged. SFAS 153 is effective for non monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not expect that the adoption of SFAS No. 153 will have an impact on the Companys financial statements.   F-14     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    In December 2004, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), (SFAS 123(R)) Share Based Payment. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 (APB 25), Accounting for Stock Issued to Employees, and generally requires that such transactions be accounted for using a fair-value-based method. This statement is effective for fiscal years beginning after June 15, 2005.  SFAS 123(R) applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date and as a
consequence future employee stock option grants and other stock based compensation plans will be recorded as expense over the vesting period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) is to be recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company will recognize stock-based compensation expense from July 1, 2005 as if the fair value based accounting method had been used to account for all outstanding unvested employee awards granted, modified or settled in prior years. The Company adopted SFAS 123(R) in 2005 and recognized $84,030 in compensation expense for options granted in 2005. The Company will recognize $112,040 in 2006 and 2007 in compensation expense relating to these options granted in 2005.The ultimate impact on results of operation and financial position in future years will depend
upon the level of stock-based compensation granted.  In March 2005, the FASB issued Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations  An Interpretation of SFAS No. 143, which clarifies the term conditional asset retirement obligation used in SFAS No. 143, Accounting for Asset Retirement Obligations, and specifically when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption did not have an impact on the Companys financial statements.  In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Correction  a replacement of APB Opinion No. 20 and FASB Statement No. 3.  This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle.  It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions.  When a pronouncement includes specific transition provisions, those provisions should be followed.  APB No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle.  This statement requires retrospective
application to prior period financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change.  The provisions of SFAS No. 154 are effective for fiscal years beginning after December 15, 2005.  F-15     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   The Company does not expect that the adoption of SFAS No. 154 will have an impact on the Companys financial statements.  (2).
        Related Party Transactions  On May 18, 2004, Dolphin Offshore Partners L.P. (Dolphin) loaned the Company $2,500,000 bearing interest at 12% per annum with interest payable monthly beginning June 18, 2004 and principal payable on May 20, 2005, which loan was secured by a first lien on the Companys Tennessee and Kansas producing properties and the Tennessee pipeline. The proceeds of the loan were used to fund in part the settlement of the Bank One litigation. Peter E. Salas, a Director of the Company and the general partner and controlling person of Dolphin, negotiated the terms of the loans directly with management, which terms were approved by management in view of the Companys immediate needs, financial condition and prospective alternatives and under circumstances in which Dolphin was not generally engaged in the business of lending money. These loans were made on terms that management
believed were at least as favorable to the Company as it could have obtained through arms-length negotiations with unaffiliated third parties.  On December 30, 2004, Dolphin loaned the Company $550,000 bearing interest at 12% per annum with interest payable monthly and principal payable on May 20, 2005, which loan was secured by lien on the Companys Tennessee and Kansas properties and the Tennessee pipeline. On March 4, 2005, Dolphin was paid $2,350,000 from the proceeds received from the sale of the Companys Kansas gas field to reduce the principal of the promissory note dated May 18, 2004 in the original amount of $2,500,000, to $150,000.With this payment the combined balances owed on the two outstanding notes to Dolphin at March 31, 2005 became $700,000. On May 19, 2005 these two notes were replaced with a single new note to Dolphin for $700,000 payable on August 20, 2005. By an amended and restated note dated August 18, 2005, the due date of the note was extended on the same terms as the existing note from August
20, 2005 to December 31, 2005.  On August 22, 2005 all holders of the Company's Series B and C Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having an aggregate value of $5,113,045.39 consisting of face value, dividends, and interest exchanged all rights under their Series B and C shares for cash or for the Company's common stock. Holders of approximately 53.2% of the face value of outstanding Series B and C shares exchanged their preferred shares having an aggregate value of $2,721,140.39 for cash payments totaling $1,814,184.30. The Company borrowed the sum of $1,814,000 from Dolphin to fund this exchange of cash for Series B & C Preferred Stock. (See Note 9 to the Financial Statements). The loan from Dolphin was evidenced by a promissory note secured by a lien on the Company's assets and bearing 12% interest per annum payable interest only monthly until the principal amount of the
note becomes due on December 31, 2005. As a result of the exchange, as of August 22, 2005 the Company no longer had any holders of Series B or C preferred stock and no further obligations under any Series B or and C shares.   F-16     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   On October 5, 2005, Hoactzin Partners, L.P. ("Hoactzin") surrendered to the Company the two outstanding promissory notes dated December 30, 2004 and August 22, 2005 made by the Company to Dolphin in the aggregate principal amount of $2,514,000. In exchange for the surrender of these notes, the Company entered into an agreement granting Hoactzin a 94.3% working interest in a twelve-well drilling program to be undertaken by the Company on its properties in Kansas. The Company will retain the remaining 5.7% working interest in the drilling program. Peter E. Salas is the controlling person of Hoactzin. As of December 31, 2005 three wells have been completed of the twelve well program. The Company reduced the Drilling Program Liability by $628,500 and offset Oil and Gas Properties by the corresponding amount. The remaining liability for this program is $1,885,500 as of December 31, 2005.  Amounts due to related parties consisted of the following:  December 31,
        2005
        2004Notes payable to a Director due May 2005 with interest payable monthly at 12% per annum. Notes were secured by Tennessee and Kansas producing properties and the pipeline
        -
        $3,050,000Total short term debt to related
parties
        -
        $3,050,000   4.
        Oil and Gas Properties  The following table sets forth information concerning the Companys oil and gas properties:  December 31,
        2005
        2004Oil and gas properties, at cost
        $16,454,183
        $  18,703,077Accumulation depreciation,
depletion and amortization
        (6,778,306)
        (5,876,174)Oil and gas properties, net
        $9,675,877
        $  12,826,903   During the years ended December 31, 2005 and 2004 the Company recorded depletion expense of $902,131 and $1,285,443 respectively.  5.
        Pipeline Facilities    F-17     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   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 $536,000, $547,161, and $536,000 in depreciation expense related to the pipeline for the years ended December 31, 2005, 2004 and 2003, respectively.  In January 1997, the Company entered into an agreement with the Tennessee Valley Authority (TVA) whereby the TVA allows the Company to bury the pipeline within the TVAs transmission line rights-of-way.  In return for this right, the Company paid $35,000 and agreed to annual payments of approximately $6,200 for 20 years.  This agreement expires in 2017 at which time the parties may renew the agreement for another 20-year term in consideration of similar inflation-adjusted payment terms.  6.
        Other Property
        and Equipment  Other property and equipment consisted of the following:  December 31,
        Depreciable Life
        2005
        2004Machinery and equipment
        5-7 yrs
        $ 771,767
        $  778,930Vehicles
        5 yrs
        494,413
        410,493Other
        5 yrs
        63,734
        63,734Total
        
        1,329,914
        1,253,157Less accumulated depreciation
        
        (1,019,166)
        (929,724)Other property and equipment - net
        
        $  310,748
        $  323,433  The Company uses the straight-line method of depreciation ranging from three years to seven years, depending on the asset life.  For the year ended December 31, 2003, the Company recorded an impairment loss on equipment totaling $495,000.       F-18     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    7.
        Long Term Debt  Long-term debt to unrelated entities consisted of the following:  December 31,
        2005
        2004Note 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 collateralized by the asset purchased with the loan.
        $20,438
        $39,399Installment notes bearing interest at the rate of 3.9% to 7% per annum collateralized by vehicles with monthly payments including interest of approximately $7,000 due through 2008.
        156,341
        93,961Total long-term debt
        176,779
        133,360Less current maturities
        (58,867)
        (26,672)Long-term debt, less current
maturities
        $117,912
        $    106,6888.
        Commitments and Contingencies  The Company is a party to lawsuits in the ordinary course of its business. 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 in the aggregate a material adverse effect on its financial statements.  In the ordinary course of business the Company has entered into various equipment and office leases which have remaining term of 21⁄2 years.  Approximate future minimum lease payments to be made under non-cancelable operating leases in 2006 are $63,346.  Office rent expense for each of the three years ended December 31, 2005, 2004 and 2003 was approximately $83,332, $ 77,110, and $78,830 respectively.  9.
        Cumulative Convertible RedeemablePreferred Stock and Conversion to Drilling Program  The Company was authorized to create and issued various classes of preferred stock (Series A, Series B and Series C). Shares of both Series A and B of Preferred Stock were immediately convertible into shares of Common Stock.  Each $100 liquidation preference share of preferred stock was convertible at a rate of $7.00 for the Series A per share of common stock.  For the Series B, the conversion rate was the average market price of the Companys common stock for 30 days before the sale of the Series B preferred stock with a  F-19     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   minimum conversion price of $9.00 per share.  The conversion rate was subject to downward adjustment for certain events.  The holders of both the Series A and Series B Preferred Stock were entitled to a cumulative dividend of 8% per quarter.  However, the payment of the dividends on the Series B Preferred Stock was subordinate to that of the Series A Preferred Stock.  The Company could 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 was outstanding, the Company was 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 (September, 2005), the Company was 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 accrued a 6% cumulative dividend on the outstanding balance, payable quarterly.  These dividends were subordinate to the dividends payable to the Series A and Series B Preferred Stock holders.  This stock was 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 was greater. The Company was required to redeem any remaining Series C Preferred Stock and any accrued and unpaid dividends in May 2007.  The Company adopted the provisions of SFAS No. 150 Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Debt (SFAS 150) on July 1, 2003. Under SFAS 150, mandatorily redeemable preferred stock shall be reclassified at fair value to a liability. The Company  determined that each of the Series A, Series B and Series C preferred stock qualify as shares subject to mandatory redemption, and as such, were reclassified as liabilities upon adoption of SFAS 150. Accordingly, the difference between the carrying amount at the date of adoption and the fair value of the shares (discounted at rates between 12% and 12.5%) was recognized as a cumulative effect of a change in accounting principle of $365,675 effective July 1, 2003. The difference between the carrying amount of shares subject to mandatory redemption and the face value amount of
preferred stock is being accreted at rates between 12% and 12.5% into interest expense and the liability until conversion or redemption of the shares. Accretion associated with these shares subject to mandatory redemption from July 1, 2003 through December 31, 2003 was $354,735 and $752,003 for 2004 and 242,007 in 2005.  In December, 2004, the Company completed an exchange offer to thirteen holders of the Companys Series A 8% Cumulative Convertible Preferred Stock in the amount of $2,867,900. Seven of the thirteen holders elected a cash exchange option, and the face amount of $1,085,000 of Series A shares was exchanged on or before December 31, 2004 for  F-20     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   cash payments of $723,370. A gain was recorded on this transaction in the amount of $458,310, the difference between the carrying amount and the cash settlement amount. The Company obtained funds for the exchange from cash on hand and the proceeds of a loan from Dolphin Offshore Partners, L.P.  The loan from Dolphin was in the form of a note in principal amount of $550,000 bearing 12% interest per annum payable interest only until due on May 20, 2005 and secured by a lien on the Companys Tennessee and Kansas assets.  Five of the thirteen Series A holders elected to participate in a drilling program in exchange for their preferred Shares, and on December 31, 2004 the amount of $1,582,900 of Series A shares plus accrued dividend of $31,658 was exchanged for approximately 6.5 Units in (the Drilling Program).  A liability was recorded for (the Drilling Program) in
the amount of $1,755,603 and Shares subject to mandatory redemption was reduced by the same amount. The Drilling Program liability recorded represents the estimated fair value of the liability calculated upon adoption of SFAS 150 less accretion, from such date to the date of the exchange. The remaining 1.5 units in the Drilling Program continue to be owned by the Company.  Under the terms of the Drilling Program, the former Series A holders participating in the Drilling Program will receive all the cash flow from each of eight wells to be drilled in Kansas, until they have recovered 80% of the value of the Series A shares exchanged.  At that point, the Company will begin to receive 85% of the cash flow from these wells as a management fee, and the former Series A owners will continue to receive 15% of the cash flow for the productive life of the wells.   In summary, twelve of the 13 holders of Series A preferred stock exchanged their Series A shares.  As a result, as of December 31, 2004 the Company had remaining only one Series A shareholder, in face amount of $200,000.  During 2005 the Company completed six wells of the eight well Drilling Program. The Company reduced the Drilling Program liability by $1,316,702 and offset oil and gas properties by the corresponding amount. This represents 75% of the Drilling Program liability on December 31, 2004. The remaining liability for this Drilling Program is $438,900.  On August 22, 2005 all holders of the Company's Series B and C Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having a total aggregate value of $5,113,045 consisting of face value, dividends, and interest exchanged all rights under their Series B and C shares for cash or for the Company's common stock. As a result of the exchange, as of August 22, 2005 the Company no longer had any holders of Series B or C preferred stock and no further obligations under any Series B and C shares.  Holders of approximately 53.2% of the face value of outstanding Series B and C shares exchanged their preferred shares having an aggregate value of $2,721,140 for cash payments totaling $1,814,184 The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin. The loan from Dolphin was evidenced by a promissory note dated August 22, 2005 secured by a lien on the Company's assets and bearing 12% interest per annum payable interest only monthly until the principal amount of the note was to become due on December 31, 2005. The note was exchanged for a twelve well Drilling Program on October 5, 2005.   F-21     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    A second option offered to the Series B and C holders was to exchange their Series B and C shares for four shares of the Company's common stock for each dollar of the face value and unpaid accrued dividends and interest on their Series B and C shares. All of the holders, including Dolphin, of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares selected this option. As a result, a total of 9,567,620 shares of the Company's common stock were issued to those holders. Of this total number, 4,595,040 shares of unregistered common stock were issued to Dolphin in exchange for the $1,148,760 in aggregate value of the Series B shares held by Dolphin.  On December 30, 2005 the Company reached an agreement to exchange the last remaining Series A 8% Cumulative Convertible Preferred Stock in the face amount of $200,000 plus $12,000 of accrued dividends for a cash settlement of $145,400. The payment was made on January 3, 2006. The $145,400 liability as of December 31, 2005 was recorded as an accrued liability on the balance sheet and a gain of $78,324 was recorded, the difference between the carrying amount of the preferred stock and the cash settlement amount.  In total, the Company recorded a gain during 2005 from the exchange of Series A, B and C shares for cash and stock of $655,746, the difference between the carrying amount and the cash settlement amount and the stock issued.   10.
        Asset Retirement Obligation  Effective January 1, 2003, the Company implemented the requirements of SFAS 143.  Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset.  Additionally, SFAS 143 requires that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed.  The Companys asset retirement obligations relate
primarily to the plugging, dismantling and removal of wells drilled to date.  The Companys calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from 30-40 years, estimated plugging and abandonment cost range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions. The Company has recorded a non-cash charge related to the cumulative effect of a change in accounting principle of $351,204 in the consolidated statements of loss for the year ended December 31, 2003.  Oil and gas properties were increased by $260,191, which represents the present value of all future obligations to retire the wells at January 1, 2003, net of  F-22     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   accumulated depletion on this cost through that date. A corresponding obligation totaling $611,395 was also recorded as of January 1, 2003.  For the years ended December 31, 2005 and 2004, the Company recorded accretion expenses of $45,965 and $73,368 in 2005 and 2004 associated with this liability. These expenses are included in interest expense in the consolidated statements of operations.  On March 4, 2005 the Company sold its Kansas gas wells, and consequently the asset and the corresponding liability relating to asset retirement obligations on these wells were extinguished. The asset account was credited for $60,998 and the liability was removed in the amount of $133,397, creating a gain on the extinguishment of future obligations in the amount of $72,399, which was credited to interest expense.  The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2005:  Balance , January 1, 2003:
        $      611,395Accretion expense
        73,368Liabilities Settled
        (16,207)Balance, December 31, 2003
        $      668,556Accretion expense
        73,368Liabilities Settled
        (33,247)Balance, December 31, 2004
        $      708,677Sale of gas wells
        (133,397)Accretion expense
        45,965Liabilities Settled
        (54,277)Balance, December 31, 2005
        $      566,968  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 3,500,000. Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company.  The purchase price of shares subject to this 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 an Employee is at least 110% of the fair market value of the Companys stock on the date of grant and such option,  by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.   F-23     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    Stock option activity in 2005, 2004 and 2003 is summarized below:  2005
        
        2004
        
        2003Shares
        Weighted
Average
Exercise
Price
        Shares
        Weighted
Average
Exercise
Price
        Shares
        Weighted
Average
Exercise
PriceOutstanding,
beginning of
year
        295,153
        $1.26
        461,590
        $    1.32
        676,770
        $    7.71Granted
        2,500,000
        .27
        -
        -
        436,000
        0.50Exercised
        (100,000)
        .27
        (142,000)
        .50
        (94,000)
        0.50Expired/
canceled
        (111,153)
        2.52
        (24,437)
        6.89
        (557,180)
        8.57Outstanding
and    exercisable,
end of year
        2,584,000
        $.29
        295,153
        $    1.26
        461,590
        $    1.32  The following table summarizes information about stock options outstanding at December 31, 2005:  Options Outstanding
        
        Options ExercisableWeighted Average
Exercise Price
        Shares
        Weighted Average
Remaining
Contractual
Life (years)
        Shares$    0.50
        184,000
        .42
        184,000$    0.27
        2,400,000
        4.33
        640,000Total
        
        2,584,000
        
        824,000  No options were granted in 2004. The weighted average fair value per share of options granted during 2005 and 2003 is $0.15 and $0.16 respectively, calculated using the Black-Scholes Option-Pricing model.  No compensation expense related to stock options was recognized in 2004 or 2003. Compensation expense of $84,030 related to stock options was recognized in 2005.  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 2005 and 2003. Expected volatility of 60% for 2005, and 40% for 2003; a risk free interest rate of 3.67% in 2005 and 2003;  and an expected option life of 2.5 years for 2005 and 3 years for 2003.   F-24     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    12.
        Income Taxes  The Company has taxable income for the period ending December 31, 2005 and no taxable income for the previous two years.  A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of income and loss is as follows:  December 31,
        2005
        2004
        2003Statutory rate
        34%
        34%
        34%Tax (benefit)/expense
at statutory rate
        370,000
        $   (678,000)
        $   (1,082,000)State income
tax (benefit)/expense
        43,000
        (79,000)
        (126,000)Other
        3,000
        (41,000)
        (65,000)Non-deductible interest
        -
        315,000
        175,000Increase/(decreases)in deferred tax asset valuation allowance
        (416,000)
        483,000
        1,098,000Total income tax provision
        -
        -
        -  The Companys deferred tax assets and liabilities are as follows:  December 31
        2005
        2004
        2003Deferred tax assets:Net operating loss carryforward
        9,616,000
        $  10,438,000
        $  9,779,000Capital loss carry forward
        263,000
        263,000
        263,000Total deferred tax assets
        9,879,000
        10,701,000
        10,042,000Deferred tax liability:
        
        -
        -Basis difference in pipeline
        400,000
        806,000
        630,000Total deferred liability
        400,000
        806,000
        630,000Total net deferred taxes
        9,479,000
        9,895,000
        9,412,000Valuation allowance
        (9,479,000)
        (9,895,000)
        (9,412,000)Net deferred liability
        -
        $     -
        $     -  The Company recorded a valuation allowance at December 31, 2005, 2004 and 2003 equal to the excess of deferred tax assets over deferred tax liabilities, as management is unable to determine the future value of the net operating loss carry-forwards.  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, 2005, the Company had net operating loss carry-forwards of approximately $24,230,000 which will expire between 2011 and 2023 if not utilized.   F-25     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    13.
        Supplemental Cash Flow Information  The Company paid approximately $524,000, $697,000, and $635,000 for interest in 2005, 2004 and 2003, respectively. No interest was capitalized in 2005, 2004 or 2003. No income taxes were paid in 2005, 2004, or 2003.  14.
        Rights Offering  On October 17, 2003, the Company filed a Registration Statement on Form S-1(the Rights Offering) with the Securities and Exchange Commission (SEC). On February 13, 2004, the SEC deemed the Registration Statement on Form S-1 effective.  The Rights Offering was a distribution to the holders of the Companys common stock outstanding at the record date, February 27, 2004, at no charge, of nontransferable subscription rights at the rate of one right to purchase three shares of the Companys common stock for each share of common stock owned at the subscription price of $0.75 in the aggregate, or $0.25 per each share purchased.  Each subscription right, in addition to the right to purchase three shares of common stock, carried with it an over-subscription privilege. The over-subscription privilege provided stockholders that exercise all of their basic subscription privileges with the opportunity to purchase those shares that were not purchased by other stockholders through the exercise of their basic subscription privileges, at the same subscription price per share.  As provided in the Rights Offering, 7,029,604 rights were exercised pursuant to the basic subscription privilege, resulting in the purchase of 21,088,812 shares at $0.25 per share for gross proceeds to the Company of $5,272,203 resulting from the basic subscription privilege. A total of 15,211,118 rights were exercised pursuant to the oversubscription privilege resulting in additional gross proceeds to the Company of $3,802,797. Of the shares purchased pursuant to the Rights Offering 14,966,344 shares were purchased by directors, officers and owners of 10% or more of the Companys outstanding common stock.  At the time the Rights Offering closed on March 18, 2004, all 36.3 million shares offered had been subscribed and, as a result, the Company raised approximately $9.1 million. The total number of shares subscribed actually exceeded the 36.3 million shares available for issuance under the offering. Consequently, all shares subscribed for under the basic privilege were issued and the number of shares issued under the over-subscription privilege was proportionately reduced to equal the number of remaining shares. The allocation and issuance of the oversubscribed shares was made by Mellon Investor Services, the Companys subscription agent who also returned payments for those over-subscribed shares that were not available.  The net proceeds of the Rights Offering were used to pay non-bank indebtedness in the aggregate amount of approximately $6 million (including $3,850,000 in principal amount plus accrued interest owed by the Company to Dolphin) and to pay $1,157,000 as a portion of  F-26     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   the Companys settlement with Bank One. The balance of the net proceeds were used for working capital purposes, including the drilling of additional wells. At December 31, 2003, the Company incurred costs in connection with the Rights Offering of $223,003, which were reflected in the consolidated balance sheet in other current assets. This asset was offset against gross proceeds in March 2004, when such proceeds were received by the Company.  15.
        Litigation Settlement  On May 10, 2004 the Court entered its final order approving the fairness of the settlement to the class, dismissing the action pursuant to a Settlement Stipulation, and fully releasing the claims of the class members inPaul Miller v. M. E. Ratliff and Tengasco, Inc.,No. 3:02-CV-644 in the United States District Court for the Eastern District of Tennessee, Knoxville, Tennessee. This action sought certification of a class action to recover on behalf of a class of all persons who purchased shares of the Companys common stock between August 1, 2001 and April 23, 2002, unspecified damages allegedly caused by violations of the federal securities laws. In January, 2004 all parties reached a settlement subject to court approval. The Court entered its order approving the settlement on May 10, 2004. Under the settlement, the Company paid
into a settlement fund the amount of $37,500 to include all costs of administration, contributed 150,000 shares of stock of Miller Petroleum, Inc. owned by the Company and issued 300,000 warrants to purchase a share of the Companys common stock for a period of three years from date of issue at $1 per share subject to adjustments.  The Rights Offering adjusted this price to $0.45 per share. The Miller Petroleum, Inc. investment had a net carrying value of $60,000 and a cumulative other comprehensive loss of $90,000, which was reversed from cumulative other comprehensive loss and recognized as a realized loss during the third quarter of 2004.  16.
        Bank One Settlement  On November 8, 2001, the Company signed a credit facility with the Energy Finance Division of Bank One, N.A. in Houston, Texas whereby Bank One extended to the Company a revolving 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 re-determined and reduced the 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 of the notice. The Company filed a lawsuit in Federal Court to prevent Bank One from exercising any rights under the Credit Agreement. As of May 1, 2004, the outstanding balance due to Bank One under the Credit Agreement was $4,101,796.  On May 13, 2004, the Company and Bank One executed a written agreement resolving all claims. The Company agreed to pay the sum of $3,657,000 to the Bank by May 18, 2004 in full satisfaction of its obligations to the Bank and to immediately release all claims against the Bank and to dismiss the litigation. In turn, Bank One agreed to immediately release all its claims against the Company, dismiss the litigation and to execute  F-27     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   releases of its liens on all of the Companys properties securing the credit facility upon receipt of the agreed payment.  On May 18, 2004, the Company paid Bank One the agreed upon settlement in the amount of $3,657,000. The funds were obtained from proceeds of loan from Dolphin Offshore Partners, LP (Dolphin) (the managing partner of Dolphin is Peter E. Salas, now Chairman of the Board of Directors), in the principal amount of $2,500,000 bearing interest at 12% per annum, payable interest only monthly beginning June 18, 2004, and with the principal amount due May 20, 2005. The balance of the settlement amount of $1,157,000 was paid from funds available to the Company from the proceeds of the Rights Offering. Upon receipt of this payment, an agreed order signed by the Company and the Bank dismissing all claims in litigation was filed with the court on May 20, 2004 and entered by the court. The Company recorded a gain from extinguishment of debt in the amount of $336,820 in the second quarter of
2004, which was the difference between the carrying amount of the loan less the settlement amount.   17.
        Sale of Kansas Gas Properties  On March 4, 2005 the Company sold its Kansas gas wells, leases and the associated gathering system in place in Rush County, Kansas to Bear Petroleum, Inc. for $2.4 million. The Companys gas producing properties in Kansas were physically separated from the oil properties, and were all located in Rush County, Kansas consisting of 51 producing gas wells and associated gathering system. All proceeds of this sale, being the sales price less a sales commission of $50,000, were immediately paid to Dolphin Offshore Partners, L.P. to reduce the principal of the promissory note to Dolphin in the amount of $2.5 million to $150,000. (See Note 2 to the Financial Statements) The Company recorded a credit to oil and gas properties of $2,350,000, the sale price net of commission. The Company also sold two small oil wells in the fourth quarter of 2005 for a total of $301,770 and recorded a
credit to Oil and Gas Properties.  18.
        Quarterly Data and Share Information (unaudited)  The following table sets forth for the fiscal periods indicated, selected consolidated financial data. Fiscal Year Ended 2005 First Quarter
        Second Quarter
        Third Quarter (b)
        Fourth Quarter (b)Revenues
        $1,431,018
        $1,612,097
        $1,879,589
        $2,250,172Net loss/income
        (418,351)
        (132,540)
        661,781
        977,138Net loss/income  attributable to common stockholders
        (418,351)
        (132,540)
        661,781
        977,138Income/loss per common share
        $(0.01)
        $(0.00)
        $0.01
        $0.02    F-28     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    Fiscal Year Ended 2004 First Quarter
        Second Quarter
        Third Quarter
        Fourth Quarter (a)Revenues
        $1,356,342
        $1,406,660
        $1,559,163
        $  1,787,309Net loss/income
        (1,216,305)
        (281,628)
        (735,819)
        239,727Net loss/income  attributable to common stockholders
        $(1,216,305)
        $(281,628)
        $ (735,819)
        $239,727   (a)
        A gain on exchange of preferred stock was recorded in the amount of$458,310, in the fourth quarter of 2004.  (b)Gains on exchange of preferred stock were recorded in the amount of                                       $577,422 in the third quarter of 2005 and $78,324 in the fourth quarter                                     of 2005.  19. Supplemental Oil and Gas Information (unaudited)  Information with respect to the Companys oil 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, 2005, 2004 and 2003.  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, 2005, 2004 and 2003:  2005
        2004
        2003Property acquisitionsProved
        $            -
        $            -
        $           -UnprovedLess proceeds from
Sales of properties
        (2,651,770)
        (77,868)Development Cost
        402,876
        1,200,771
        480,421$(2,248,894)
        $1,122,903
        $480,421  Results of Operations from Oil and Gas Producing Activities   F-29     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements   The following table sets forth the Companys results of operations from oil and gas producing activities for the years ended:  December 31,
        2005
        2004
        2003Revenues
        $  7,076,790
        $  6,013,374
        $  6,040,872Production costs and          taxes
        (2,956,307)
        (3,241,905)
        (3,412,201)Depreciation, depletion     and amortization
        (902,132)
        (1,285,443)
        (1,268,470)Income from oil and         gas producing activities
        $  3,218,351
        $  1,486,026
        $    1,360,201  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 operating tax loss carry-forwards.  Oil and Gas Reserves (unaudited)  The following table sets forth the Companys net proved oil and gas reserves at December 31, 2005, 2004 and 2003 and the changes in net proved oil and gas reserves for the years then ended.  Proved reserves represent the 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.  Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (Mcf) in the case of gas.  Oil (bbls)
        Gas (Mcf)Balance, December 31, 2002
        1,475,899
        26,598,733Discoveries and extensions
        -
        -Revisions of previous estimates
        42,478
        (11,633,157)Production
        (147,243)
        (620,873)Balance, December 31, 2003
        1,371,134
        14,344,703Discoveries and extensions
        41,054
        -Revisions of previous estimates
        (190,585)
        (5,913,179)Production
        (131,603)
        (484,524)Balance, December 31, 2004
        1,090,000
        7,947,000Discoveries and extensions
        25,768
        -Sale of Reserves
        -
        (2,350,000)Revisions of previous estimates
        403,247
        (629,633)Production
        (144,552)
        (204,128)Proved reserves at December 31, 2005
        1,374,463
        4,763,239    F-30     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    Proved developed producing
reserves at December 31, 2005
        1,091,135
        2,814,306Proved developed producing
reserves at December 31, 2004
        783,000
        5,342,000Proved developed producing
reserves at December 31, 2003
        1,059,038
        5,167,832  Of the Companys total proved reserves as of December 31, 2005, 2004 and 2003, approximately 72%, 69% and 51% respectively, were classified as proved developed producing, 14%, 17%, and 14% respectively, were classified as proved developed non-producing and 14%,14%, and 35% respectively, were classified as proved undeveloped. All of the Companys reserves are located in the continental United States.  Standardized Measure of Discounted Future Net Cash Flows (unaudited)  The standardized measure of discounted future net cash flows from the Companys proved oil and gas reserves is presented in the following two tables:  (amounts in thousands)December 31,
        2005
        2004
        2003Future cash inflows
        $130,584
        $  100,516
        $  109,102Future production
costs and taxes
        (55,625)
        (47,129)
        (48,761)Future development costs
        (1,494)
        (1,757)
        (5,957)Future income tax expenses
        -
        -
        -Net future cash flows
        73,465
        51,630
        54,384Discount at 10% for
timing of cash flows
        (36,286)
        (24,899)
        (28,021)Discounted future net cash flows from proved reserves
        $37,179
        $  26,731
        $  26,363(amounts in thousands)2005
        2004
        2003Balance, beginning of year
        $26,731
        $  26,363
        $  46,648Sales, net of production costs
and taxes
        (4,121)
        (2,772)
        (2,884)Discoveries and extensions
        453
        595
        -Changes in prices and
production costs
        13,537
        11,127
        (9,040)Revisions of quantity estimates
        4,559
        (12,574)
        (13,988)Sale of Reserves
        (4,856)
        -
        -    F-31     Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements    Interest factor - accretion
of discount
        2,673
        2,636
        4,665Net change in income taxes
        -
        -
        -Changes in future development costs
        262
        4,201
        5,391Changes in production rates
and other
        (2,059)
        (2,845)
        (4,429)Balance, end of year
        $37,179
        $  26,731
        $  26,363  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, 2005, 2004, and 2003 were $55.81, $40.92, and $29.72 per barrel of oil and $11.31, $7.04, and $4.76 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 properties.  Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.  Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable  net operating loss carry-forwards, for both regular and alternative minimum tax. For the years ended December 31, 2005, 2004 and 2003 the Companys available net operating loss carry forwards offset all tax effects applicable to the discounted future net cash flows.  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-32