UNITED STATES
Securities and Exchange Commission
Washington, D.C. 20549

Report on Form 10-K

(Mark one)

|X| Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 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 of incorporation 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 if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes [ ] No |X| Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No |X|

        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

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 I

ITEM 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.

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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

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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	6/17/02
2306 West Gallaher Ferry	Officer (1)
Knoxville, TN 37932
Mark A. Ruth	Chief Financial	12/14/98
9400 Hickory Knoll Lane	Officer
Knoxville, TN 37931
Robert M. Carter	President Tengasco	6/1/98
760 Prince George Parish Drive	Pipeline Corporation
Knoxville, TN 37931
Cary V. Sorensen	Vice-President;	07/9/99
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.

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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

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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.

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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.

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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.

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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

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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.

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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.

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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.

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			TENNESSEE
Year ended December 31	Production				Cost of Production (per BOE) (3)		Average Sales Price
	Oil (Bbl)		Gas (Mcf)				Oil (Bbl)		Gas (Per Mcf)
2005		10,818		183,399	$	18.864	$	53.90	$	8.74
2004		13,515		223,078	$	15.525	$	36.57	$	6.13
2003		19,277		384,238	$	7.62	$	26.87	$	5.38

			KANSAS
Year ended December 31	Production				Cost of Production (per BOE) (3)		Average Sales Price
	Oil (Bbl)		Gas (Mcf)				Oil (Bbl)		Gas (Per Mcf)
2005		128,765		20,7296	$	15.33	$	53.48	$	5.02
2004		115,701		261,455	$	13.62	$	39.41	$	4.86
2003		104,511		206,194	$	15.65	$	29.00	$	4.73

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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	Completed 3/11/05	3,254 bbl
Dick "A" # 8	Completed 4/11/05	1,417 bbl
Ridgway "A" #4	Completed 6/16/05	7,755 bbl
Urban "A" # 6	Completed 9/21/05	1,560 bbl
Kraus "AA" # 3	Completed 10/13/05	174 bbl
Ben Tempero "A" # 3	Drilled and Abandoned	n/a

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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	Drilled and Abandoned	n/a
Foster B # 9	Completed 11/16/05	1,030 bbl
Lowry	Completed 1/25/06	early production approximately 40 bbl per day

        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

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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
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Tennessee
Productive Wells	0	0	1	0.875	0	0
Dry Holes	0	0	1	0.828	0	0
Kansas
Productive Wells	7	0.9175	1	0.875	0	0

Dry Holes 2 0.2163 0 0 0 0

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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
	Gross		Net			Gross		Net
Tennessee		21		14	.50		5		4
Kansas		0		0			130		105

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
	Gross Acres		Net Acres		Gross Acres		Net Acres
Tennessee		1,280		742		18,241		15,960
Kansas		11,735		10,013		4,140		3,622

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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	$	0	.34	$	0	.19
June 30, 2005		0	.28		0	.19
September 30, 2005		0	.51		0	.22
December 31, 2005		0	.88		0	.39
March 31, 2004		1	.21		0	.38
June 30, 2004		0	.53		0	.37
September 30, 2004		0	.40		0	.22
December 31, 2004		0	.35		0	.23

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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.

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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	Weighted-average	Number of securities
	to be issued upon	exercise price of	remaining available
	exercise of	outstanding, options,	for future issuance
	outstanding options,	warrants and rights	under equity
	warrants and rights	compensation plans
			(excluding securities
			reflected in column
	(a)	(b)	(a)) (c)
Equity compensation
plans approved by
security holders(7)	2,584,000	$0.29	313,638
Equity compensation
plans not approved
by security holders	0	N/A	0
Total	2,584,000	$0.29	313,638

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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	$	6,013,374		$	6,040,872		$	5,437,723		$	6,656,758
Production Costs and Taxes	$	3,046,460	$	3,364,429		$	3,412,201		$	3,094,731		$	2,915,746
General and Administrative	$	1,322,616	$	1,177,183		$	1,486,280		$	1,868,141		$	2,957,781
Interest Expense	$	472,655	$	1,367,180		$	1,120,738		$	578,039		$	850,965
Net Income/Loss	$	1,088,028	$	(1,994,025	)	$	(3,197,662	)	$	(3,154,555	)	$	(2,262,787	)
Net Income/Loss	$	1,088,028	$	(1,994,025	)	$	(3,451,580	)	$	(3,661,334	)	$	(2,653,970	)
Attributable to Common
Stockholders
Net Income/Loss Attributable	$	0.02	$	(0.05	)	$	(0.29	)	$	(0.33	)	$	(0.26	)
to Common Stockholders Per
Share

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As of December 31, ^{(9) (10)}

	2005			2004			2003			2002			2001
Balance Sheet Data:
Working Capital Deficit	$	(1,334,744	)	$	(6,753,721	)	$	(10,822,717	)	$	(7,998,835	)	$	(6,326,204	)
Oil and Gas Properties, Net	$	9,675,877		$	12,826,903		$	12,989,443		$	13,864,321		$	13,269,930
Pipeline Facilities, Net	$	13,994,453		$	14,602,639		$	15,139,789		$	15,372,843		$	15,039,762
Total Assets	$	25,908,616		$	29,209,749		$	30,604,240		$	32,584,391		$	32,128,245
Long-Term Debt	$	117,912		$	1,940,890		$	6,256,818		$	2,006,209		$	3,902,757
Redeemable Preferred Stock	$	-0-		$	-0-		$	-0		$	6,762,218		$	5,459,050
Stockholders Equity	$	21,961,454		$	18,349,687		$	11,251,871		$	14,210,623		$	14,991,847

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.

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        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.

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        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.

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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.

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        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.

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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

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.

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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

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.

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CONTRACTUAL OBLIGATIONS

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

			Payments Due By Period
Contractual Obligations	Total		Less than 1year		1-3 years		3-5 years	More than 5 years
Long-Term Debt Obligations(11)	$	176,779	$	58,867	$	117,912	$-0-	$-0-
Capital Lease Obligations	$	-0-	$	-0-	$	-0-	$-0-	$-0-
Operating Lease Obligations(12)	$	158,365	$	63,346	$	95,019	$-0-	$-0-
Purchase Obligations	$	-0-	$	-0-	$	-0-	$-0-	$-0-
Other Long-Term Liabilities(13)	$	2,324,400	$	2,324,400	$	-0-	$-0-	$-0-
Total	$	2,659,544	$	2,446,613	$	212,931	$-0-	$-0-

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

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

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.

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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.

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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.

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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.

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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

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)

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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

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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. Bailey
Jeffrey R. Bailey,
Chief Executive Officer

By: s/Mark A. Ruth
Mark A. Ruth,
Principal Financial and Accounting Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.

Signature Title Date

s/Clarke H. Bailey	Director	March	16	, 2006
Clarke H. Bailey
s/Jeffrey R. Bailey	Director;	March	20	, 2006
Jeffrey R. Bailey	Chief Executive Officer
s/John A. Clendening	Director	March	17	, 2006
John A. Clendening
s/Neal F. Harding	Director	March	16	, 2006
Neal F. Harding
s/Carlos P. Salas	Director	March	20	, 2006
Carlos P. Salas
s/Peter E. Salas	Director;	March	16	, 2006
Peter E. Salas	Chairman
s/Mark A. Ruth	Principal Financial	March	20	, 2006
Mark A. Ruth	and Accounting Officer

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    ⁽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-3
Consolidated Financial Statements
Consolidated Balance Sheets	F-4– F-5
Consolidated Statements of Operations	F-6
Consolidated Statements of Stockholders’ Equity                                       F-7
Consolidated Statements of Cash Flows	F-8– F-9
Notes 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	2004
Assets(Note 1)
Current
Cash and cash equivalents	$260,969	$      267,735
Accounts receivable	1,154,405	706,752
Participant receivables	9,777	73,016
Inventory	496,331	341,745
Other current assets	6,056	67,526
Total current assets	1,927,538	1,456,774
Oil and gas properties, net (on the basis of full cost accounting) (Notes 4 and 18)	9,675,877	12,826,903
Pipeline facilities, netof accumulated depreciation of $ 2,335,099 and $1,812,204 (Note 5)	13,994,453	14,602,639
Other 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	2004
Liabilities and Stockholders’ Equity (Note 1)
Current liabilities
Current maturities of long-term debt (Note 7)	$      58,867	$      26,672
Accounts payable	597,278	319,820
Accrued interest payable	-	25,367
Other accrued liabilities	281,737	211,622
Notes payable to related parties (Note 2)	-	3,050,000
Drilling program (Note 9)	2,324,400	1,316,702
Current shares subject to mandatory redemption (Note 9)	-	3,260,312
Total current liabilities	3,262,282	8,210,495
Shares subject to mandatory redemption (Note 9)	-	1,395,301
Drilling program (Note 9)	-	438,901
Asset retirement obligations (Note 10)	566,968	708,677
Long term debt, less currentmaturities(Note 7)	117,912	106,688
Total liabilities	3,947,162	10,860,062
Commitments 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	48,928
Additional paid-in capital	54,200,345	51,686,283
Accumulated 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	2003
Revenues and other income
Oil and gas revenues	$     7,076,790	$     6,013,374	$     6,040,872
Pipeline transportation revenues	94,911	92,599	163,393
Interest Income	1,175	3,501	985
Total revenues and other income	7,172,876	6,109,474	6,205,250
Costs and expenses
Production costs and taxes	3,046,460	3,364,429	3,412,201
Depreciation, depletion and amortization Notes 4, 5 and 6)	1,605,043	2,067,566	2,308,007
General and administrative	1,322,616	1,177,183	1,486,280
Interest expense (Notes 9, 10 and 13)	472,655	1,367,180	1,120,738
Public relations	30,020	35,347	31,183
Professional fees	263,800	779,180	549,503
Loss on impairment of long-lived asset	-	-	495,000
Loss on sale of equipment, net	-	107,744	-
Total costs and expenses	6,740,594	8,898,629	9,402,912
Net 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)	-	-	365,675
Net 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)	-	-	0.03
Total	$     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-In Capital			Accumulated Deficit			Comprehensive Loss			Accumulated Other Comprehensive Income (Loss)			Treasury Stock Shares		Amount			Total
	Shares	Amount
Balance, December 31, 2002	11,630,130		11,631		42,237,105			(27,776,726	)		—			(115,500	)	14,500			(145,887	)		14,210,623
Net loss	—		—		—			(3,197,662	)		—			—		—			—			(3,197,662)
Cumulative effects of changes in accounting       principles	—		—		—			14,471			—			—		—						14,471
Comprehensive loss:
Net loss	—		—		—			—			(3,197,662	)		—		—						—
Other comprehensive gain	—		—		—			—			25,500			25,500		—						25,500
2003 comprehensive loss	—		—		—			—			(3,172,162	)		—		—			—			—
Common stock issued in private placements,       net of related expenses	227,275		227		249,773			—			—					—			—			250,000
Common stock issued on conversion of debt	60,528		61		69,538			—			—					—			—			69,599
Common stock issued for charity	3,571		4		5,710			—			—					—			—			5,714
Common stock issued for services	55,500		70		(64,458	)		—			—					(14,500	)		145,887			81,499
Common stock issued for exercised in arrears       options	94,000		94		46,906			—			—					—			—			47,000
Common stock issued for preferred       dividends in arrears	154,824		154		170,155			—			—					—			—			170,309
Common stock issued for litigation       settlement	10,000		10		6,390			—			—					—			—			6,400
Accretion of issue cost on preferred stock-       series B & C	—		—		—			(163,193	)		—					—			—			(163,193)
Dividends on convertible redeemable       preferred stock	—		—		—			(268,389	)		—					—			—			(268,389)
Balance, December 31, 2003	12,235,828		12,251		42,721,119			(31,391,499	)		—			(90,000	)	—			—			11,251,871
Net Loss	—		—		—			(1,994,025	)		—					—			—			(1,994,025)
Common stock issued for exercised options	142,000		142		70,858						—					—			—			71,000
Common stock issued in Rights Offering	36,300,000		36,285		8,812,056						—					—			—			8,848,341
Common stock issued for services	250,000		250		82,250						—					—			—			82,500
Transfer of investment (Note 15)	—		—		—						—			90,000		—			—			90,000
Balance, December 31, 2004	48,927,828		48,928		51,686,283			(33,385,524	)		—			—		—			—			18,349,687
Net Income	—		—		—			1,088,028			—			—		—			—			1,088,028
Common Stock issued for exercised options	100,000		100		26,900			—			—			—		—			—			27,000
Options Expense	—		—		84,030			—			—			—		—			—			84,030
Lawsuit Settlement	4,000		4		19,366			—			—			—		—			—			19,370
Conversion of Stock	9,567,620		9,568		2,381,418			—			—			—		—			—			2,390,986
Common Stock issued for exercise of Warrants	5,230		5		2,348			—			—			—		—			—			2,353
Balance, 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	2003
Operating activities
Net 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	2,308,007
Compensation and services paid in stock options, stock   arrants, and common stock	103,400	82,500	203,812
Loss on impairment of long-lived assets	-	-	495,000
Accretions of redeemable shares and A.R.O., net	233,696	792,124	459,691
Gain 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)	222,289
Participant receivables	63,239	(4,614)	2,203
Inventory	(154,586)	(61,052)	(17,945)
Other assets	61,470	155,477	14,613
Accounts payable – trade	277,458	(756,129)	(320,813)
Accrued interest payable	(25,367)	(208,954)	173,179
Other accrued liabilities	70,115	193,062	(13,244)
Net cash (used in) provided by Operating activities	2,113,763	(370,137)	316,027
Investing activities
Additions 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	1,945,202
Decrease (additions) to pipeline facilities	72,186	(10,001)	(5,775)
Other	-	-	74,207
Sale of Kansas Properties	2,651,770	-	-
Net cash (used in) provided by Investing activities	2,166,854	(876,854)	(65,069)
Financing activities
Proceeds from exercise of options/warrants	29,352	71,000	47,000
Proceeds from borrowings	155,073	3,310,815	3,256,171
Repayments of borrowings	(3,182,636)	(9,848,560)	(3,432,470)
Proceeds from issuance of common stock	2,391,905	8,848,341	250,000
Dividends 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)	128,536
Cash 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	$   312,666
Supplemental disclosure of non-cash investing and financing activities:
Issuance of common stock on conversion of debt/preferred stock	$2,391,905	-	$    69,549
Issuance of common stock and stock options for services received    and charitable contributions made	- -	-	$   203,812
Capitalization of lawsuit settlement relating to the pipeline	-	-	$   297,171
Capitalization of future asset retirement obligations to oil and gas    properties	-	-	$   346,922
Conversion 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		2003
Net loss attributable to common shareholders
As 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 share
As 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	2004
Notes 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	-	$3,050,000
Total 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	2004
Oil and gas properties, at cost	$16,454,183	$  18,703,077
Accumulation 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	2004
Machinery and equipment	5-7 yrs	$ 771,767	$ 778,930
Vehicles	5 yrs	494,413	410,493
Other	5 yrs	63,734	63,734
Total		1,329,914	1,253,157
Less 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	2004
Note payable to a financial institution, with $1,773 principal payments due monthly beginning January 7, 2002 through December 7, 2006. Interest is payable monthly commencing on January 7, 2002 at 7.5% per annum. Note is collateralized by the asset purchased with the loan.			$20,438	$    39,399
Installment 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	93,961
Total long-term debt			176,779	133,360
Less current maturities			(58,867)	(26,672)
Long-term debt, less current maturities			$117,912	$    106,688
	8.	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 2½ 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 Redeemable
	Preferred 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:	$      611,395
Accretion expense	73,368
Liabilities Settled	(16,207)
Balance, December 31, 2003	$      668,556
Accretion expense	73,368
Liabilities Settled	(33,247)
Balance, December 31, 2004	$      708,677
Sale of gas wells	(133,397)
Accretion expense	45,965
Liabilities 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		2003
	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price
Outstanding, beginning of year	295,153	$1.26	461,590	$    1.32	676,770	$    7.71
Granted	2,500,000	.27	-	-	436,000	0.50
Exercised	(100,000)	.27	(142,000)	.50	(94,000)	0.50
Expired/ canceled	(111,153)	2.52	(24,437)	6.89	(557,180)	8.57
Outstanding 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 Exercisable
	Weighted 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	640,000
Total		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	2003
Statutory 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	175,000
Increase/(decreases)in deferred tax asset valuation allowance	(416,000)	483,000	1,098,000
Total income tax provision	-	-	-

The Company’s deferred tax assets and liabilities are as follows:

December 31	2005	2004	2003
Deferred tax assets:
Net operating loss carryforward	9,616,000	$  10,438,000	$  9,779,000
Capital loss carry forward	263,000	263,000	263,000
Total deferred tax assets	9,879,000	10,701,000	10,042,000
Deferred tax liability:		-	-
Basis difference in pipeline	400,000	806,000	630,000
Total deferred liability	400,000	806,000	630,000
Total net deferred taxes	9,479,000	9,895,000	9,412,000
Valuation 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 in Paul 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	$2,250,172
Net loss/income	(418,351)	(132,540)	661,781	977,138
Net loss/income attributable to common stockholders	(418,351)	(132,540)	661,781	977,138
Income/loss per common share	$(0.01)	$(0.00)	$0.01	$0.02

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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	$ 1,787,309
Net loss/income	(1,216,305)	(281,628)	(735,819)	239,727
Net 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	2003
Property acquisitions
Proved	$            -	$            -	$           -
Unproved
Less –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

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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	2003
Revenues	$  7,076,790	$  6,013,374	$  6,040,872
Production 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	26,598,733
Discoveries and extensions	-	-
Revisions of previous estimates	42,478	(11,633,157)
Production	(147,243)	(620,873)
Balance, December 31, 2003	1,371,134	14,344,703
Discoveries 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		7,947,000
Discoveries 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

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Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements

Proved developed producing reserves at December 31, 2005	1,091,135	2,814,306
Proved developed producing reserves at December 31, 2004	783,000	5,342,000
Proved 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			2003
Future cash inflows	$130,584		$  100,516			$  109,102
Future 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			54,384
Discount 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	2003
Balance, beginning of year		$26,731		$  26,363	$  46,648
Sales, 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)		-	-

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Tengasco, Inc. and SubsidiariesNotes to Consolidated Financial Statements

Interest factor - accretion of discount	2,673	2,636	4,665
Net change in income taxes	-	-	-
Changes in future development costs	262	4,201	5,391
Changes 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