10-K 1 annuallreport2004_10kmarch31.htm ANNUAL REPORT

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, 2004 or

/ / Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to .

Commission File No. 0-20975

TENGASCO, INC.

(Name of registrant as specified in its charter)

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

603 Main Avenue, Knoxville, Tennessee 37902
(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code: (865) 523-1124.

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.001 par value per share.

Indicate by checkmark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes /X/ No / /

Indicate by checkmark if disclosure of delinquent filers in response to Item 405 of Regulation SK is not contained in this form and no disclosure will be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act): Yes / / No /X/

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second quarter (June 30, 2004 closing price $0.38): $11,854,484

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 (February 1, 2005): 48,927,828

Documents Incorporated By Reference: None.

Table of Contents		Page
PART I	Item 1. Business.....................................................................................	1
	Item 2. Properties..................................................................................	16
	Item 3. Legal Proceedings...........................................................................	24
	Item 4. Submission of Matters to a Vote of Security Holders.........................................	24
PART II	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities..............................................................................	25
	Item 6. Selected Financial Data.....................................................................	27
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation............................................................................................................	28
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk....................................	37
	Item 8. Financial Statements and Supplementary Data.................................................	38
	Item 9. ...........Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.........................................................................................................	38
	Item 9A. Controls and Procedures..........................................................................................	39
	Item 9B. Other Information................................................................................................	40
PART III	Item 10. Directors and Executive Officers of the Registrant...........................................	40
	Item 11. Executive Compensation.......................................................................	47
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters...................................................................................................	50
	Item 13. Certain Relationships and Related Transactions....................................................................	53
	Item 14. Principal Accountant Fees and Services............................................................................	55
PART IV	Item 15. Exhibits and Financial Statement Schedules............................................................................	56
SIGNATURES	..................................................................................................................................	59

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 2004 and thereafter; the Company’s ability to continue as a going concern; 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 1 of this Report.

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.

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.

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

The Company’s activities in the oil and gas business commenced in May 1995 with the acquisition of oil and gas leases in Hancock, Claiborne, Knox, Jefferson and Union counties in Tennessee. The Company’s current lease position in these areas in Tennessee is approximately 21,188 acres.

To date, the Company has drilled primarily on a portion of its Tennessee leases known as the Swan Creek Field in Hancock County focused within what is known as the Knox formation, one of the geologic formations in that field. During 2004, the Company produced an average of approximately 611 thousand cubic feet of natural gas per day and 1,126 barrels of oil per month from 22 producing gas wells and five producing oil wells in the Swan Creek Field.

In 2001, the Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) which was formed to 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.

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 2004, the Kansas Properties produced an average of approximately 716 MMcf of natural gas per day and 9,840 barrels of oil per month. Gross revenues from the Kansas Properties during 2004 were $4,606,901.

General

1. The Swan Creek Field

Amoco Production Company, during the late 1970‘s and early 1980‘s acquired approximately 50,500 acres of oil and gas leases in the Eastern Overthrust in the Appalachian Basin, including the area now referred to as the Swan Creek Field. In 1982, Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the Knox Formation. 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 $11.1 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 $16,414,842.

B. Swan Creek Production and Development

The Company began delivering gas through its pipeline in April 2001 and deliveries to Eastman began in May 2001. Daily production in June 2001 averaged 4,936.2 Mcf and in July 2001 daily production averages increased to 5,497 Mcf per day. Although the Company’s gas production in mid-2001 was at anticipated levels, the Company was unable to maintain those production levels. This was due to initial fluid problems in some wells as well as natural production declines from the type of reservoir that actual production has now shown to exist in the Swan Creek Field. The Company had initially intended to offset expected natural declines in production by drilling new wells, but was largely prevented from doing so during

2002 through 2004 due to ongoing disputes with Bank One, the Company’s principal lender, and the resulting lack of available capital. That dispute was finally settled in May 2004.

After the Bank One lawsuit was resolved, the Company drilled two new wells in 2004 in the Swan Creek Field to the Knox Formation. This resulted in one producing well, the Steve Lawson #8, which is currently producing approximately 10,000 cubic feet of natural gas per day. 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 it is anticipated that upon final review it will be plugged.

Because the Knox formation of the Swan Creek Field has been now been more specifically defined by the accumulation of data from previously drilled wells and seismic data, the Company now 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.

Further, 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 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 745 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 was expected and does not diminish either the shut-in pressure or the Company’s actual reserves in the Swan Creek Field. The declines, however, suggest the production rates from some of the Company’s 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, that the total volume of its reserves remains largely intact, and that these reserves can be extracted primarily through existing wells.

Natural gas production from the Swan Creek Field during 2004 averaged 611 thousand cubic feet per day compared to 1.053 million cubic feet per day in 2003.

During 2004, the Company had 22 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 — Description of Property — 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.

2. The Kansas Properties

In 1998, the Company acquired the Kansas Properties, which presently include 129 producing oil wells and 51 producing gas wells in the vicinity of Hays, Kansas and a 50 mile gas gathering system. The Company also acquired 37 other wells, which now serve as saltwater disposal wells in the vicinity of Hays, Kansas. These saltwater disposal wells 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 2004 was 716 Mcf of gas and 326 barrels of oil per day. Revenue for the Kansas Properties was approximately $383,909 per month in 2004. The Company employs a full time geologist in Kansas to oversee operations of the Kansas Properties.

In 2004, the Company drilled one new well in Kansas, the Lewis No. 3 Well. This well was drilled to the Arbuckle formation, and is currently producing 39 barrels of oil per day. In December 2004, the Company commenced a lease acquisition program in Kansas and as of the date of this report, has increased its lease position from 32,158 acres to 42,895 acres by acquiring oil and gas leases in an area 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 “Drilling Program” or the “Program”). The 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. 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. 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. For a further discussion of this drilling program see, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation” — “Liquidity and Capital Resources”.

In addition, there are several capital development projects that the Company has considered to increase current oil production with respect to the Kansas Properties, including recompletion of wells and major workovers. Management has made the decision to undertake as many of these projects as may be paid from current cash flow, as the Company does not presently have the necessary funds to perform all workovers simultaneously. 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 in Kansas from many of the Company’s other existing oil wells.

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 believes that there is a limited possibility of significant additional net revenues being obtained by the Company from these properties. Consequently, on March 4, 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.

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 any 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 when combined 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.

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.

Natural gas from the Kansas Properties is delivered to Oneok Bushton Processing, Inc. in Bushton, Kansas. At present, crude oil is sold to the National Cooperative Refining Association in McPherson, Kansas, 120 miles from Hays. National Cooperative is solely responsible for transportation of the oil it purchases whether by truck or pipeline.

Drilling Equipment

On July 28, 2004 the Company sold an Ingersoll Rand RD20 drilling rig and related 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’s principal competitors in the State of Tennessee are Nami Resources, LLC, Miller Petroleum, Inc. and Knox Energy Development. Nami Resources, Miller Petroleum, and Knox Energy Development are in the business of exploring for and producing oil and natural gas in the Kentucky and East Tennessee areas. These companies are in competition with the Company for lease positions in the 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.

Natural gas from the Kansas Properties is delivered to Kansas-Nebraska Energy, Inc. in Bushton, Kansas. At present, crude oil from the Kansas Properties is being trucked and transported through pipelines to the National Cooperative Refining Association in McPherson, Kansas, 120 miles from Hays, Kansas. National Cooperative is solely responsible for transportation of products whether by truck or pipeline.

Patents, Trademarks, Licenses, Franchises, Concessions,
Royalty Agreements or Labor Contracts, Including Duration

Royalty agreements relating to oil and gas production are standard in the industry. The amount of the Company’s royalty payments varies from lease to lease.

Need For Governmental Approval of Principal Products or Services

None of the principal products offered by the Company require governmental approval, 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 approvals necessary to transport natural gas to all customers of the Company.

The City of Kingsport, Tennessee has also 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.

TPC presently has all required tariffs and approvals necessary to transport natural gas to all customers of the Company.

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 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 and the home telephone numbers of key personnel. A list is maintained at the Company’s office and at the home of key personnel listing phone numbers for fire, police, emergency services and Company employees who will be needed to deal with emergencies.

The foregoing is only a brief summary of some of the existing environmental laws, rules and regulations to which the Company’s business operations are subject, and there are many others, the effects of which could have an adverse impact on the Company. Future legislation in this area will no doubt be enacted and revisions will be made in current laws. No assurance can be given as to what effect these present and future laws, rules and regulations will have on the Company’s current and future operations.

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-four full time employees and no part-time employees.

Risk Factors

In addition to the other information in this document, investors in the Company’s common stock should consider carefully the following risks with respect to the Company’s business operations:

                  The Company’s Auditors Have Issued Their Audit Report,
                  Which Includes An Explanatory Paragraph Emphasizing
                  Substantial Doubt About the Company’s Ability To Continue
                  As A Going Concern For One Year From The Balance
                  Sheet Date (December 31, 2004).

Management has disclosed in the notes to the Company’s Consolidated Financial Statements for the year ended December 31, 2004, certain circumstances that raise substantial doubt about the Company’s ability to continue as a going concern, which depends upon the Company’s ability to obtain long-term financing or raise capital to satisfy the Company’s cash flow requirements. 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. Although the Company anticipated that after the resolution of its dispute with its primary lender, Bank One, it would be able to find alternative institutional sources of financing for its activities; to date it has been unable to do so. The Company’s inability to obtain a replacement credit facility to fund its operations combined with the fact that the Company is still in the early stages of its oil and gas operating history, during which time it has a history of losses from operations and has an accumulated deficit of $33,385,524 and a working capital deficit of $6,753,721 as of December 31, 2004, the Company’s Independent Registered Public Accounting Firm issued their report which emphasized the substantial doubt about the Company’s ability to continue as a going concern as described above.

At the present time and if and until the Company is able to obtain institutional financing, the Company must obtain the necessary funds to proceed with the Company’s operations from 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 procure additional financing, 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 continue in business. Where 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. In addition to the Company’s operational cash requirements, the Company has a significant amount of loans and other obligations either due or maturing May 25, 2005. As a result of the sale of the gas producing properties in Kansas, the Company was able to reduce amounts owed on high-interest debts. As of the filing date of this report, the Company’s remaining interest-bearing loans have an aggregate principal amount of approximately $700,000. The Company also has accrued and unpaid dividends on preferred stock in an aggregate amount in excess of $649,000. See below, “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources.” The Company can make no assurances that it will be able to obtain any additional funding required as described above, in which event it may not be able to continue as a going concern.

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.

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 Company’s investment. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.

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.

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.

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 addition, the Company is presently in a weak financial condition. In seeking any suitable oil and gas properties for acquisition, or drilling rig operators and related personnel and equipment, the Company is not 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 Able To 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.

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.

ITEM 2. PROPERTIES

Property Location, Facilities, Size and Nature of Ownership

Swan Creek Field

The Company’s Swan Creek Leases are on approximately 21,188 acres in Hancock, Claiborne, Knox, Jefferson, Morgan and Union Counties in Tennessee. The initial terms of these leases vary from one to five years. Some of them will terminate unless the

Company has commenced drilling. In 2002, the Company reduced the acreage comprising the Swan Creek Field from approximately 50,500 acres to 41,088 acres. In 2003, the acreage in the Swan Creek Field was again reduced to 28,338 acres. In 2004, the acreage in the Swan Creek was further reduced to the present 21,188 acres. These reductions in acreage were a result of the Company having a better understanding of the geological and geophysical makeup of the Swan Creek Field. Management believes the acreage eliminated from the Field does not have the potential to produce commercial quantities of oil or gas and that the reduction of this acreage does not affect the reserves of the Swan Creek Field. Further, the elimination of the leases for this acreage will result in beneficial cost savings to the Company.

Morita Properties, Inc., an affiliate of Shigemi Morita, a former Director of the Company, currently has a 25% overriding royalty in nine of the Company’s existing wells, and a 50% overriding royalty and 6% overriding royalty, respectively, in two of the Company’s other existing wells. All of these wells are located in the Swan Creek Field and all but two are presently producing wells. In addition, to those interests, Morita Properties, Inc. previously owned a 25% working interest in three of the Company’s other existing wells and 12.5% working interest in another of the Company’s wells which it subsequently sold.

An individual who is not an affiliate of the Company purchased 25% working interests in two other wells, the Stephen Lawson No. 1 and the Patton No. 1. Both of these wells are located in the Swan Creek Field. 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, are to be 81.25% to Miller. The Company’s subsidiary TPC will transport Miller’s gas. The Company reserved all offset locations to wells drilled under the farmout agreement. All ten wells have been drilled under the farmout agreement. The Company acquired back from Miller a 50% working interest from Miller in nine of those ten wells in addition to its rights under the farmout agreement. In addition, the Company and Miller have drilled two additional wells on a 50-50 basis, although the Company declined to exercise its option for a ten-well extension of the farmout agreement. Of the wells in which Miller owns an interest, six are presently producing.

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

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

Kansas Properties

The Kansas Properties as of December 31, 2004 contained 138 leases totaling 42,895 acres in the vicinity of Hays, Kansas. The increase in the Company’s acreage in Kansas from 32,158 acres in 2003 to the current total is due to the Company’s acquisition of new leases in those areas close to its existing, productive wells. The Company intends to increase its acreage in Kansas through the continued acquisition of new leases. The terms on the Company’s original leases in the Kansas properties were from 1 to 10 years and in most cases have expired. Most of these leases, however, are still in effect because they are being held by production. The Company maintains a 100% working interest in most wells. The leases provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%.

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

The Company leases its principal executive offices, consisting of approximately 5,647 square feet located at 603 Main Avenue, Suite 500, Knoxville, Tennessee at a rental of $5,176 per month and an office in Hays, Kansas at a rental of $500 per month.

Reserve Analyses

Ryder Scott Company, L.P. of Houston, Texas (“Ryder Scott”) has performed reserve analyses of all the Company’s productive leases. Ryder Scott and its employees and its registered petroleum engineers have no interest in the Company, and performed these services at their standard rates. The net reserve values used hereafter were obtained from a reserve report dated January 17, 2005 (the “Report”) prepared by Ryder Scott as of December 31, 2004.

The Report indicates the Company’s “TOTAL PROVEN ALL CATEGORIES” reserves for the Company to be as follows: net production volumes of 1,090,000 barrels of oil and 7,947 MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be $26,731,142. The Report indicates the “proven developed producing” reserves for the Company to be as follows: net production volumes of 783,000 barrels of oil and 5,342 MMCF of gas. The pre-tax present value discounted at 10% (PV10) is stated to be $17,304,770.

In substance, the Report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical factors. Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies, commercial services, outside operators and files of Ryder Scott. The net reserve values in the Report were adjusted to take into account the working interests that have been sold by the Company in various wells in the Swan Creek Field.

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

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

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

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.

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

ii.

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

iii.

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

Production

The following tables summarize for the past three fiscal years the volumes of oil and gas produced to the Company’s interests, the Company’s operating costs and the Company’s average sales prices for its oil and gas. The information does not include volumes produced to royalty interests or other working interests.

			TENNESSEE
Year ended December 31	Production				Cost of Production (per BOE)1		Average Sales Price
	Oil (Bbl)		Gas (Mcf)				Oil (Bbl)		Gas (Per Mcf)
2004		13,515.00		223,078.00	$	15.52²	$	36.57	$	6.13
2003		19,277.00		384,238.00	$	7.62	$	26.87	$	5.38
2002		15,111.54		521,834.35	$	4.10	$	21.85	$	3.22

			KANSAS
Year ended December 31	Production				Cost of Production (per BOE)		Average Sales Price
	Oil (Bbl)		Gas (Mcf)				Oil (Bbl)		Gas (Per Mcf)
2004		115,701.00		261,455.00	$	13.62	$	39.41	$	4.86
2003		104,511.00		206,194.00	$	15.65	$	29.00	$	4.73
2002		105,473.54		246,510.98	$	8.71	$	23.89	$	2.96

Oil and Gas Drilling Activities

The Company’s oil and gas developmental drilling for the past three fiscal years are as set forth in the following tables. 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.

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 and it is anticipated that upon final review it will be plugged.

In August 2004, the Company, based on 3D seismic data also drilled one well in Kansas to the Arbuckle formation, the Lewis #3. This well is currently producing approximately 39 barrels per day and has produced 3,785 gross barrels since its completion. The success of the Lewis #3 and the ongoing success of the Company and the industry in Kansas through the use of 3D seismic data indicates that the potential return on drilling investments in Kansas remains strong.

During the past three fiscal years, the Company drilled one exploratory well in 2002 in Cocke County, Tennessee which did not result in finding commercial quantities of hydrocarbons.

Gross and Net Wells

The following tables set forth for the fiscal years ending December 31, 2002, 2003, and 2004 the number of gross and net development wells drilled by the Company. The dry holes set forth in the table below are the Cocke County well and the Hazel Sutton #3 in the Swan Creek Field 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
	2004					2003						2002
	Gross		Net			Gross			Net			Gross			Net
Tennessee Productive Wells		1		0	.875			0			0			3	2.625

Dry Holes		1		0	.828			0			0			1	.50

Kansas

Productive Wells		1		0	.875			0			0			3	2.594

Dry Holes		0		0			0			0			0		0

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, 2004. 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		22		15		5		4

Kansas		51		43		129		113

Developed and Undeveloped Oil and Gas Acreage

As of December 31, 2004, the Company owned working interests in the following developed and undeveloped oil and gas acreage. Net acres refers to the Company’s interest less the interest of royalty and other working interest owners.


	DEVELOPED					UNDEVELOPED
	Gross Acres			Net Acres		Gross Acres		Net Acres
Tennessee		1,280			742		19,908		17,450


Kansas		12, 73	0		10,311		30,165		24,886

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 2004.

PART II

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

Market Information

The Company’s common stock is listed on the American Stock Exchange (“AMEX”) under the symbol TGC. The range of high and low closing prices for shares of common stock of the Company during the fiscal years ended December 31, 2004 and December 31, 2003 are set forth below.

For the Quarters Ending
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
March 31, 2003	2	.00	1	.00
June 30, 2003	1	.23	0	.36
September 30, 2003	1	.28	0	.65
December 31, 2003	0	.94	0	.63

Holders

As of February 1, 2005 the number of shareholders of record of the Company’s common stock was 242 and management believes that there are approximately 3,246 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 2004 and has no present plans to declare any further dividends with respect to its common stock.

Recent Sales of Unregistered Securities

On December 28, 2004, the Company issued 100,000 shares of restricted shares of its common stock each to Clarke H. Bailey and John A. Clendening and 50,000 shares of restricted stock to Neal F. Harding who are Directors of the Company for their services as members of the Company’s Audit Committee. No other equity securities that were not registered under the Securities Act of 1933, as amended, were sold or issued by the Company during 2004.

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 2004.

The Rights Offering

On October 17, 2003, the Company filed a Registration Statement on Form S-1 with the SEC for a rights offering of the Company’s common stock (the “Rights Offering”). On December 29, 2003; February 11, 2004; and February 13, 2004, the Company filed amendments to the Registration Statement. On February 13, 2004, the SEC deemed effective the Registration Statement on Form S-1 as amended.

The Rights Offering was a distribution to the holders of the Company’s common stock outstanding at the record date, February 27, 2004, at no charge, of nontransferable subscription rights at the rate of one right to purchase three shares of the Company’s common stock for each share of common stock owned at the subscription price of $0.75 in the aggregate, or $0.25 per each share purchased.

The record date for the Rights Offering was set as of February 27, 2004. The offering expired at 5:00 p.m., New York City time, on March 18, 2004.

Each subscription right in addition to the right to purchase three shares of common stock carried with it an over-subscription privilege. The over-subscription privilege provided stockholders that exercise all of their basic subscription privileges with the opportunity to purchase those shares that were not purchased by other stockholders through the exercise of their basic subscription privileges at the same subscription price per share. In no event could any subscriber purchase shares of the Company’s common stock in the offering that, when aggregated with all of the shares of the Company’s common stock otherwise owned by the subscriber and his, her or its affiliates, would immediately following the closing represent more than 50% of the Company’s issued and outstanding shares.

The net proceeds of the Rights Offering were initially used to pay non-bank indebtedness in the aggregate amount of up to approximately $6 million (including to satisfy all of the Company’s outstanding loans to Dolphin in the principal amount of $3,850,000 plus accrued interest) the balance of the net proceeds were used to repay bank indebtedness and for working capital purposes, including the drilling of additional wells. See, “Item 13 -“Certain Relationships and Related Transactions.”

At the time the Rights Offering closed on March 18, 2004 all 36.3 million shares offered had been subscribed for and, as a result the Company raised approximately $9.1 million. The total number of shares subscribed for actually exceeded the 36.3 million shares available for issuance under the offering. Consequently, all shares subscribed for under the basic privilege were issued and the number 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 oversubscribed shares that were not available.

Pursuant to the Rights Offering, 7,029,604 rights were exercised pursuant to the basic subscription privilege, resulting in the purchase of 21,088,812 shares at $0.25 per share for gross proceeds to the Company of $5,272,203. A total of 15,211,188 shares were purchased pursuant to the oversubscription privilege, resulting in additional gross proceeds to the Company of $3,802,797. See, Item 13 — “Certain Relationships and Related Transactions” for a complete list of the shares purchased pursuant to the Rights Offering by Directors and Officers of the Company and entities controlled by such persons.

ITEM 6. SELECTED FINANCIAL DATA

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

Years Ended December 31^3,

	2004			2003			2002			2001			2000
Income Statement Data:
Oil and Gas Revenues	$	6,013,374		$	6,040,872		$	5,437,723		$	6,656,758		$	5,241,076

Production Costs and Taxes	$	3,364,429		$	3,412,201		$	3,094,731		$	2,951,746		$	2,614,414

General and Administrative	$	1,177,183		$	1,486,280		$	1,868,141		$	2,957,871		$	2,602,311

Interest Expense	$	1,367,180		$	1,120,738		$	578,039		$	850,965		$	415,376

Net Loss		(1,994,025	)	$	(3,197,662	)	$	(3,154,555	)	$	(2,262,787	)	$	(1,541,884

Net Loss Attributable to				$
Common Stockholders	$	(1,994,025	)	$	(3,451,580	)	$	(3,661,334	)	$	(2,653,970	)	$	(1,799,441	)

Net Loss Attributable to
Common Stockholders Per Share	$	(0.05	)	$	(0.29	)	$	(0.33	)	$	(0.26	)	$	(0.19	)

As of December 31^{4 5 6} ,

	2004			2003			2002			2001			2000
Balance Sheet Data:
Working Capital Deficit	$	(6,753,721	)	$	(10,822,717	)	$	(7,998,835	)	$	(6,326,204	)	$	(708,317	)

Oil and Gas Properties, Net	$	12,826,903		$	12,989,443		$	13,864,321		$	13,269,930		$	9,790,047

Pipeline Facilities, Net	$	14,602,639		$	15,139,789		$	15,372,843		$	15,039,762		$	11,047,038

Total Assets	$	29,209,749		$	30,604,240		$	32,584,391		$	32,128,245		$	25,224,724

Long-Term Debt	$	1,940,890		$	6,256,818		$	2,006,209		$	3,902,757		$	7,108,599

Redeemable Preferred Stock		0			0		$	6,762,218		$	5,459,050		$	3,938,900

Stockholders Equity	$	18,349,687		$	11,251,871		$	14,210,623		$	14,991,847		$	10,864,202

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

Results of Operations

The Company incurred a net loss to holders of common stock of $1,994,025 ($0.05 per share) in 2004 compared to a net loss of $3,451,580 ($0.29 per share) in 2003 and compared to a net loss of $3,661,344 ($0.33 per share) in 2002.

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 drill rig during 2004 of $107,744.See, Note 16 in the Company’s Notes to the Consolidated Financial Statements in Item 8 of this report.

The Company realized oil and gas revenues of $6,013,374 in 2004 compared to $6,040,872 in 2003 and compared to $5,437,723 in 2002. Revenues remained stable in 2004 from 2003 levels with a slight increase in 2003 from 2002 levels due to increases in prices received for sales of oil and gas. The volume of gas sold from the Swan Creek Field decreased to 223,078 Mcf in 2004 from 384,238 Mcf in 2003 and the volume of oil sold from Swan Creek Field decreased to 13,515 barrels in 2004 from 24,284 barrels in 2003. The decline in volumes of oil and gas produced in the Swan Creek Field from existing wells is normal for any producing well and the declines as experienced were not unexpected. The decrease in volumes was offset by increases in price of the oil and gas volumes sold. Oil and gas volumes produced from the Company’s Kansas Properties remained relatively constant, experiencing expected small declines in production consistent with the age of the producing properties. Again, such declines are normal and are expected to continue.

Gas prices received for sales of gas from the Swan Creek Field averaged $6.13 per Mcf in 2004, $5.38 in 2003, and $3.22 in 2002. Oil prices received for sales of oil from the Swan Creek field averaged $36.57 in 2004, $26.87 in 2003, and $21.85 in 2002. Gas prices received for sales of each Mcf of gas in Kansas averaged $4.86 in 2004, $4.73 in 2003, and $2.96 in 2002. Oil prices received for sales of oil in Kansas averaged $39.41 per barrel in 2004, $29.00 in 2003, and $23.89 in 2002.

The Company’s subsidiary, TPC, had pipeline transportation revenues of $92,599

in 2004, a decrease from $163,393 in 2003 and $259,677 in 2002 resulting from the decrease in volumes of gas produced from the Swan Creek Field.

The Company’s production costs and taxes have increased from 2002 to 2004. Production costs and taxes in 2004 of $3,364,429 remained consistent with 2003 levels. The production costs and taxes increased in 2003 to $3,412,201 from $3,094,731 in 2002. This increase was due to the fact that the Company’s field personnel cost was capitalized as the Company was drilling new wells in 2002, compared to 2003 and 2004. In 2003 and 2004 all employees were working to maintain production and these costs, including field salaries in Swan Creek, were expensed. The remaining increase is due to increased property taxes on the pipeline because it has been assessed at a higher value after completion.

Depletion, depreciation, and amortization decreased to $2,067,566 in 2004 from $2,308,007 in 2003 and $2,413,597 in 2002. The decrease in 2004 was due to declines in volumes produced and a reduction in depreciation taken on equipment sold in 2004.

The Company reduced its general administrative costs to $1,177,183 in 2004 from $1,486,280 in 2003 and $1,868,141 in 2002 . 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 and 2002 levels and utilization of existing employees to perform drafting and file preparation services previously performed by third parties at additional cost. The Company also closed its New York office in late 2002 and a field office in Tennessee in 2003.

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

Interest expense for 2004 increased significantly over 2003 and 2002 levels due to the adoption of Financial Accounting Standards Board Statement of Financial Accounting Standards No. 143 (“SFAS 143”) which deals with asset retirement obligations and SFAS No.150 regarding preferred stock and dividends on preferred stock being recognized as interest expense beginning in the third quarter of 2003. Interest expense in 2004 was $1,367,180 compared to $1,120,738 in 2003 and $578,039 in 2002.

Public relations costs were significantly reduced to $35,347 in 2004 and $31,183 in 2003, compared to $193,229 in 2002 as the Company applied cost saving methods in the preparation of its annual report and in publishing of press releases.

Professional fees in 2004 were $779,180 compared to $549,503 in 2003 and $707,296 in 2002. These fees remained at a high level due to legal services primarily related to the Bank One litigation.

Dividends on preferred stock decreased to $0 in 2004 from $268,389 in 2003 and $506,789 in 2002, 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. See, Note 9 to the Company’s Consolidated Financial Statements for more information.

Liquidity and Capital Resources

On November 8, 2001, the Company signed a credit facility agreement with the Energy Finance Division of Bank One, N.A. in Houston, Texas. The Company instituted litigation in May 2002 based on certain actions taken by Bank One. On May 13, 2004, the Company resolved its dispute with Bank One. The Company had anticipated that when its dispute with Bank One was resolved it would be able to obtain financing from other institutional lenders to allow the Company to continue to both develop existing properties and locate and purchase additional properties. To date, however, due to the financial status of the Company including debt obligations owed, the Company’s credit history, and the inability of the Company to pay accrued distributions on its preferred stock, the Company has not been able to establish a banking relationship with another institutional lender. Although management continues to attempt to locate a source or sources of institutional financing for Company operations, there can be no assurances that such relationships can be established or that bank financing will be obtained or of the terms of such relationship.

Management believes that the Company has made significant progress in 2004 in meeting the Company’s obligations under previous financing vehicles for Company operations and positioning the Company for future growth. In 2004, all material litigation involving the Company was resolved, eliminating the substantial ongoing costs and expenses of such litigation to the Company. In 2004, the Company’s rights offering 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. In addition, unsecured convertible notes entered into in 1998 in the principal amount of $1.5 million were fully paid; and other convertible notes entered into in 2002 in the original principal amount of $650,000 were paid in full in March 2004.

Additionally, 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 amount of $2,867,900. Seven of the thirteen holders elected to exchange their shares for cash. Accordingly, the face amount of $1,085,000 of Series A Shares was exchanged on or before December 31, 2004 for $723,370 in cash. 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 recognized a gain on shares exchanged for cash of $458,310 as of December 31, 2004. The loan from Dolphin was in the form of a note in principal amount of $550,000 bearing 12% interest per annum interest only payable 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 shareholders selected the “Drilling Program” exchange option and on

December 31, 2004 the face value of $1,582,900 of Series A Shares plus dividend valued at $31,658 were exchanged for approximately 6.5 units in the Program. The remaining 1.5 units in the Drilling Program continue to be owned by the Company. Under the terms of the Drilling Program exchange, the former Series A shareholders 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. As a result, as of December 31, 2004 the Company has remaining only one Series A shareholder owning Series A Shares with a face value of $200,000. Management believes this was a successful and beneficial exchange for both the Company and the former Series A shareholders.

On March 4, 2005, the Company sold its gas producing properties in Rush County, Kansas for $2.4 million and used the net proceeds of the sale to pay down the $2.5 million debt incurred by the Company to fund the settlement of the litigation with Bank One in May, 2004. This has the effect of reducing the payment of high interest on this note, and reducing the total secured debt owed by the Company to approximately $700,000 as of the date of this report, consisting of about $150,000 remaining principal of the $2.5 million note, and the principal of the $550,000 note used for the cash exchange of Series A Shares.

As a result of the payment of this secured and unsecured debt, and the exchange of most of the Series A Shares, management believes the Company is now better positioned to both establish a banking relationship with an institutional lender on acceptable terms to fund the Company’s activities. Although the Company is hopeful that as a result of the substantial reduction of its debt position that it will soon be able to establish such a relationship, there is no assurance it will be able to do so. Until the Company is able to establish such a relationship, it will be necessary to fund its operations, including capital expenditures for the acquisition, exploration and development of oil and gas reserves from other sources, such as the rights offering as well as equity investment, private loans or a joint venture with other companies, as to which there can be no assurances. In addition to its operational cash requirements, the Company also has a significant amount of loans and other obligations which will either become due or mature on May 18, 2005, including secured promissory notes due to Dolphin in the principal amount of $700,000 plus interest thereon, as well as the payment of the accrued distributions on the Company’s Series B 8% Cumulative Convertible Preferred Stock in the amount of $180,000, and the scheduled redemption of both the Series B and Series C 6% Cumulative Convertible Preferred Stock which become due on August 25, 2005 and April 30, 2007, respectively. See, “Item 13 — Certain Relationships and Related Transacti ns.”

As of December 31, 2004, the Company had total stockholders’ equity of $18,349,687 and total assets of $29,209,749. The Company had a net working capital deficiency at December 31, 2004 of $6,753,721 compared to a net deficiency of $10,822,717 at December 31, 2003.

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. 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 $825,371. Cash flow used in working capital items in 2004 was $913,831 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 operating activities for 2003 was $316,027 as compared to net cash used in operating activities of $566,017 in 2002. The Company’s net loss in 2003 increased to $3,197,662 from $3,154,555 in 2002. The impact on cash provided by operating activities was due to the net loss for 2003 and was primarily offset by non-cash depletion, depreciation, and amortization of $2,308,007, non-cash compensation and services paid by insurance of equity instruments of $203,812, loss on impairment of long-term assets of $495,000 and accretion of liabilities of $459,691. Cash flow from working capital items in 2003 was $60,282 as compared to $126,321 in 2002. This resulted from decreases in 2003 from 2002 in accounts payable of $320,813 and in accounts receivable of $222,289 and an increase in accrued interest payable in 2003 from 2002 of $173,179.

Net cash used in 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 investing activities amounted to $65,069 for 2003 compared to $2,889,937 for 2002. The decrease in net cash used for investing activities during 2003 was primarily attributable to the fact that in 2003 additions to oil and gas properties was $133,501 compared to $1,982,529 in 2002. In 2003 there was a reduction in expenditures used for the construction of Phase II of the pipeline system from $841,750 in 2002 to $5,775, and in 2003 the Company did not make any expenditures for additions to other property and equipment whereas in 2002 the Company expended $214,897 for these items.

Net cash provided by financing activities increased to $1,202,060 in 2004 from cash used by 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.

Net cash used in financing activities amounted to $122,422 in 2003 compared to net cash provided by financing activities of $3,246,633 in 2002. The primary sources of

financing include proceeds from borrowings of $3,256,171 in 2003 compared to $2,063,139 in 2002, private placements of common stock of $250,000 in 2003 compared to $2,677,000 in 2002, convertible redeemable preferred stock of $1,303,168 in 2002 compared to none in 2003 and proceeds from the exercise of options of $47,000 in 2003 compared to none in 2002. The primary use of cash in financing activities was the repayment of borrowings of $3,432,470 in 2003 compared to $2,378,273 in 2002.

Critical Accounting Policies

The Company’s accounting policies are described in the Notes to Consolidated Financial Statements in Item 8 of this Report. The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company’s financial statements and the uncertainties that could impact the Company’s results of operations, financial condition and cash flows.

Revenue Recognition

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

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and non-productive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, daily rentals and the costs of drilling, completing and equipping oil and gas wells. The Company capitalized $1,122,903, $480,421 and $1,982,529 of these costs in 2004, 2003 and 2002, respectively. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if

any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write-downs were recorded in 2004, 2003 or 2002.

Oil and Gas Reserves/Depletion Depreciation
and Amortization of Oil and Gas Properties

The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.

The Company’s proved oil and gas reserves as at December 31, 2004 were estimated by Ryder Scott, L.P., Petroleum Consultants. Projecting the effects of commodity prices on production, and timing of development expenditures include many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.

Asset Retirement Obligations

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

Recent Accounting Pronouncements

FAS 141-1 and FSP FAS 142-1. Historically the Company has included the cost of such mineral rights as tangible assets, which is consistent with the EITF’s consensus. As such , EITF 04-02 will not affect the Company’s consolidated condensed financial statements.

Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of FASB Statement No. 143, Accounting for Asset Retirement Obligations, by oil and gas producing companies following the full cost accounting method was issued in September 2004. SAB 106 provided an interpretation of how a company, after adopting Statement 143, should compute the full cost ceiling to avoid double-counting the expected future cash outflows associated with asset retirement costs. The provisions of this interpretation have been applied by the Company and has no impact on the financial statements.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This statement is a revision to SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. Companies will be required to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service, the requisite service period (usually the vesting period), in exchange for the award. The grant date fair value of employee share options and similar instruments will be estimated using option-pricing models. If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modifications. SFAS No. 123R will be effective for periods beginning after June 15, 2005 and allows for several alternative transition methods. Accordingly, the Company will adopt SFAS No. 123R in its third quarter of fiscal 2005. The Company is currently evaluating the provisions of SFAS No. 123R and has not determined the impact that this Statement will have on its results of operations or financial position.

CONTRACTUAL OBLIGATIONS

The following table summarizes the Company’s contractual obligations at December 31, 2004:

	Payments Due By Period
Contractual Obligations	Total		Less than 1year		1-3 years		3-5 years	More than 5 years
Long-Term Debt Obligations⁷	$	7,838,973	$	6,336,984	$	1,501,989	$-0-	$-0-
Capital Lease Obligations	$	-0-	$	-0-	$	-0-	$-0-	$-0-
Operating Lease Obligations⁸	$	62,117	$	62,117	$	-0-	$-0-	$-0-
Purchase Obligations	$	-0-	$	-0-	$	-0-	$-0-	$-0-
Other Long-Term Liabilities⁹	$	1,755,603	$	1,316,702	$	438,901	$-0-	$-0-
Total	$	9,656,693	$	7,715,803	$	1,940,890	$-0-	$-0-

The Company has entered into a Drilling Program with former holders of its Series A Preferred Stock. The Company is contractually obligated to drill 8 wells in the Program, 6 of which are expected to be completed in 2005. The Company has recorded an aggregate liability of $1,755,603 on its consolidated balance sheet as of December 31, 2004. This amount is included in “Other Long-Term Liabilities” in the table above.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Risk

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of $29.77 per barrel to a high of $51.12 per barrel during 2004. Gas price realizations ranged from a monthly low of $4.11 per Mcf to a monthly high of $7.78 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, 2004, the Company had debt outstanding of approximately $3,183,000 at a fixed rate. The Company did not have any open derivative contracts relating to interest rates at December 31, 2004.

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

None.

ITEM 9A CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Securities Exchange Act of 1934, as amended, including this Report, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

The Company’s management, including the Company’s President and Chief Financial Officer (the “Certifying Officers”), as previously reported in the Company’s Quarterly Report on Form 10-Q for the quarter ending September 30, 2004 concluded that in one matter in 2004 that the Company’s disclosure controls and procedures were not effective with respect to that matter 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. The 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.” The Company previously reported that this deficiency constituted a material weakness, and detailed the facts surrounding the matter. 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 determined that continuing education and professional development of accounting staff on new accounting pronouncements and their application would be sufficient to prevent any similar reoccurrence. The Company is continuing to provide necessary and appropriate educational and professional development and believes that such efforts have remediated the material weakness described herein. As a result, the Company’s Certifying Officers have concluded based on their evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended, as of the date of this Report were effective to ensure that material information was accumulated and communicated to management, including the Company’s Certifying Officers, as appropriate to allow timely decisions regarding required disclosure in the Company’s filings with the SEC.

Changes in Internal Controls

Except as noted above, there have been no changes to the Company’s system of internal control over financial reporting during the quarter ended December 31, 2004 that has

materially affected, or is reasonably likely to materially affect, the Company’s system of controls over financial reporting.

ITEM 9B OTHER INFORMATION

None.

PART III

ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Identification of Directors and Executive Officers

The following table sets forth the names of all current directors and executive officers of the Company. These persons will serve until the next annual meeting of stockholders (to be held at such time as the Board of Directors shall determine) or until their successors are elected or appointed and qualified, or their prior resignations or terminations.

Name	Positions Held	Date of Initial Election or Designation
Clarke H. Bailey	Director	8/12/04
1865 Palmer Avenue
Larchmont, NY 10538

Jeffrey R. Bailey	Director;	2/28/03-8/11/04;10/21/04
2306 West Gallaher Ferry	President	6/17/02
Knoxville, TN 37932

John A. Clendening	Director	2/28/03
1031 Saint Johns Drive
Maryville, TN 37801
Neal F. Harding	Director	8/12/04
2509 Plantside Drive
Louisville, KY 40299
Carlos P. Salas	Director	8/12/04
129 East 17th Street
New York, NY 10003
Peter E. Salas	Director	10/8/02
129 East 17th Street	Chairman of the Board	10/21/04
New York, NY 10003

Name	Positions Held	Date of Initial Election or Designation
Richard T. Williams	Director	6/28 /02
4472 Deer Run Drive
Louisville, TN 37777
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 379194	Secretary

Richard T. Williams resigned as Chief Executive Officer of the Company as of December 31, 2004. Effective January 1, 2005, the Company merged all duties of the Chief Executive Officer with and into the office of President of the Company, currently held by Jeffrey R. Bailey, and the position of Chief Executive Officer was eliminated.

Business Experience

Directors

Clarke H. Bailey is 50 years old. He is currently Chairman of the Board and Chief Executive Officer of Glenayre Technologies, Inc. (NasdaqNM:GEMS), a company engaged in the development and sale of software and equipment in the wireless communications industry. He has been a director of Glenayre since December 1990, Chairman since October 1999, and CEO since October 2003. From January 1999 to March 2002 he was Chairman and CEO of ShipXact.com, Inc. From February 1995 to January 1998 he was Chairman and CEO of United Acquisition Company and its parent, United Gas Holding Corporation until their acquisition by Iron Mountain Incorporated (NYSE:IRM), a records and information management services company, in 1998. He has served on the Board of Directors of Iron Mountain since January 1998. He also served as Chairman of Arcus, Inc. from July 1995 to January 1998, and Co-Chairman of Highgate Capital L.L.C. from February 1995 to March 2002. He holds a Bachelor’s degree in Economics and a Bachelor’s degree in Rhetoric from the University of California, Davis and a Master of Business Administration degree from The Wharton School, University of Pennsylvania. Mr. Bailey serves as the Chairman of the Company’s Audit Committee and as the financial expert of that Committee.

Jeffrey R. Bailey is 47 years old. He graduated in 1980 from New Mexico

Institute of Mining and Technology with a B.S. degree in Geological Engineering. Upon graduation he joined Gearhart Industries as a field engineer working in Texas, New Mexico, Kansas, Oklahoma and Arkansas. Gearhart Industries later merged with Halliburton Company. In 1993 after 13 years working in various field operations and management roles primarily focused on reservoir evaluation, log analysis and log data acquisition he assumed a global role with Halliburton as a Petrophysics instructor in Fort Worth, Texas. His duties were to teach Halliburton personnel and customers around the world log analysis and competition technology and to review analytical reservoir problems. In this role Mr. Bailey had the opportunity to review reservoirs in Europe, Latin America, Asia Pacific and the Middle East developing a special expertise in carbonate reservoirs. In 1997 he became technical manager for Halliburton in Mexico focusing on finding engineering solutions to the production challenges of large carbonate reservoirs in Mexico. He joined the Company as its Chief Geological Engineer on March 1, 2002. He was elected as President of the Company on July 17, 2002 and as a Director on February 28, 2003 and served as a Director until August 11, 2004. He was again elected to the Company’s Board of Directors on October 21, 2004.

Dr.John A. Clendening is 73 years old. He received B.S. (1958), M.S. (1960) and Ph. D. (1970) degrees in geology from West Virginia University. He was employed as a Palynologist-Coal Geologist at the West Virginia Geological Survey from 1960 until 1968. He joined Amoco in 1968 and remained with Amoco as a senior geological associate until 1992. Dr. Clendening has served as President and other offices of the American Association of Stratigraphic Palynologists and the Society of Organic Petrologists. From 1992 — 1998 he was engaged in association with Laird Exploration Co., Inc. of Houston, Texas, directing exploration and production in south central Kentucky. In 1999 he purchased all the assets of Laird Exploration in south central Kentucky and operates independently. While with Amoco Dr. Clendening was instrumental in Amoco’s acquisition in the early 1970‘s of large land acreage holdings in Northeast Tennessee, based upon his geological studies and recommendations. His work led directly to the discovery of what is now the Company’s Paul Reed # 1 well. He further recognized the area to have significant oil and gas potential and is credited with discovery of the field which is now known as the Company’s Swan Creek Field. Dr. Clendening previously served as a Director of the Company from September 1998 to August 2000. He was again elected as a Director of the Company on February 28, 2003.

Neal F. Harding is 63 years old. He received a Bachelors of Science degree in Social Sciences from Campbellsville University in 1964. He is the Chairman and Chief Executive Officer of the Heritage Companies based in Cocoa Beach, Florida which are three management companies specializing in the development, construction, and management of more than 6,000 single and multi-family affordable housing units. Mr. Harding through various partnerships, currently owns in excess of 16,000 affordable housing units throughout the country. He is the owner of R.M.D. Corp., the largest franchisee of Hooters restaurants. He is also the majority shareholder of World Wide Wings, a Hooters franchisee which owns and manages six international units located in Canada and England. Mr. Harding is also the majority shareholder in F & H Development Company, which owns and operates a semi-public PGA-designed 18-hole golf course in Sikeston, Missouri. Additionally, Mr. Harding is the sole shareholder of

Harding Construction Services, Inc., a real estate company specializing in the acquisition and development of commercial and residential properties. Mr. Harding is the exclusive franchisee of Qdoba Mexican Grill Restaurants in south Florida. Mr. Harding previously served as a director of the Company from August 31, 1999 to August 7, 2000.

Carlos P. Salas is 33 years old. He is a principal of Dolphin Advisors, L.L.C., which manages a private-equity investment fund focused on middle-market opportunities. Before joining Dolphin Advisors, Mr. Salas led an investor group in the acquisition of a private engineering and manufacturing firm in 2001, and joined the company to lead a financial and operating restructuring as CFO in 2002. Previously, Mr. Salas led corporate finance and mergers and acquisitions advisory assignments for middle-market clients as an investment banker with the Los Angeles office of Donaldson, Lufkin & Jenrette (“DLJ”), and when DLJ was acquired by Credit Suisse First Boston Corporation (“CSFB”), joined CSFB’s mergers and acquisitions group. Prior to joining DLJ in 1999, Mr. Salas practiced law with Cleary, Gottlieb, Steen & Hamilton in New York, advising financial sponsors and corporate clients in connection with financings and cross-border mergers and acquisitions transactions. Mr. Salas received his J.D. from The University of Chicago in 1996, and his B.A. in Philosophy from New York University in 1992. He was elected to the Company’s Board of Directors on August 12, 2004.

Peter E. Salas is 50 years old. He has been President of Dolphin Asset Management Corp. and its related companies since he founded it in 1988. Prior to establishing Dolphin, he was with J.P. Morgan Investment Management, Inc. for ten years, becoming Co-manager, Small Company Fund and Director-Small Cap Research. He received an A.B. degree in Economics from Harvard in 1976. Mr. Salas was elected to the Board of Directors on October 8, 2002.

Dr. Richard T. Williams is 54 years old. He has been a member of the faculty of the Department of Geological Sciences at The University of Tennessee in Knoxville, Tennessee, since 1987, after holding faculty positions at West Virginia University and the University of South Carolina since 1979. He has been engaged in reflection seismology and geophysical studies in the Appalachian Overthrust since 1980. He earned his Ph.D. in Geophysics from Virginia Tech in 1979. Dr. Williams was elected to the Board of Directors of the Company effective June 28, 2002. He was appointed Chief Operating Officer of the Company on January 10, 2003, and on February 3, 2003, he was elected Chief Executive Officer of the Company. He served in that position until December 31, 2004.

Officers

Mark A. Ruth is 46 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. From December 14, 1998 to August 31, 1999 he served as the Company’s Chief Financial Officer. On August 31, 1999 he was elected as a Vice-President of the Company and on November 8, 1999 he was again appointed as the Company’s Chief Financial Officer.

Robert M. Carter is 68 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, most recently serving for seven years as senior counsel with the litigation department of Enron Corp. before entering private practice in June, 1996. He has represented virtually all of the major oil companies headquartered in Houston and all of the operating subsidiaries of Enron Corp., as well as local distribution companies and electric utilities in a variety of litigated and administrative cases before state and federal courts and agencies in five states. These matters involved gas contracts, gas marketing, exploration and production disputes involving royalties or operating interests, land titles, oil pipelines and gas pipeline tariff matters at the state and federal levels, and general operation and regulation of interstate and intrastate gas pipelines. He has served as General Counsel of the Company since July 9, 1999.

Committees

The Company’s Board has operating audit, nomination and governance, compensation/stock option, and frontier exploration committees.

Clarke H. Bailey, Neal F. Harding and John A. Clendening are the members of the Company’s audit committee. Mr. Bailey is the Chairman of this committee and the Board of Directors has determined that Mr. Bailey is an “audit committee financial expert” as defined by applicable SEC regulations. Each of the members of the audit committee meets the independence and experience requirements of the applicable laws, regulations and stock market rules, including the Sarbanes-Oxley Act, regulations and rules promulgated by the Securities and Exchange

Commission and the American Stock Exchange.

Mr. Harding, Clarke H. Bailey and Carlos P. Salas, with Mr. Salas acting as Chairman, are the members of the nomination and governance committee which, among other duties, determines the slate of director candidates to be presented for election at the Company’s annual meeting of shareholders. On November 18, 2004, the nominating/governance committee adopted procedures for the process of nominating persons for election to the Company’s Board of Directors. Among the procedures adopted were the method by which shareholders of the Company could nominate individuals for election to the Board. The nomination procedures are posted on the Company’s internet website at www.Tengasco.com. The procedures adopted have not been amended. However, in the event of any such amendment to the procedures, the Company intends to disclose the amendments on the Company’s internet website within five business days following such amendment.

Mr. Clendening and Carlos P. Salas are the members of the compensation/stock option committee. Richard T. Williams, Jeffrey R. Bailey, Carlos P. Salas and Mr. Clendening comprise the frontier exploration committee.

Family Relationships/Arrangements

There are no family relationships between any of the present directors or executive officers of the Company except that Carlos P. Salas, a Director of the Company, is the second cousin of Peter E. Salas, also a director of the Company. Mr. Carlos P. Salas is also one of seven members of Dolphin Advisors, LLC which serves as the managing general partner of Dolphin Direct Equity Partners, L.P., a private company investment fund that is not a shareholder of the Company. The majority owner of Dolphin Advisors, LLC is Dolphin Management, Inc, the sole shareholder of which is Peter E. Salas. Dolphin Management, Inc. is also the managing partner of Dolphin Offshore Partners, L.P. which directly owns 16,244,452 shares of the Company’s common stock. Peter E. Salas is the controlling person of Dolphin Offshore Partners, L.P. Although Carols P. Salas has no direct or indirect ownership interest in Dolphin Offshore Partners, L.P., he nonetheless may be deemed an affiliate of Dolphin Offshore Partners, L.P. and Peter E. Salas.

There is no family or other relationship between Clarke H. Bailey, a Director of the Company and Jeffrey R. Bailey, the President and a Director of the Company. Mr. Clarke H. Bailey owns an approximately 1.5% investment interest in Dolphin Offshore Partners, L.P. and in Dolphin Direct Equity Partners, L.P. Management believes that Mr. Bailey is not an affiliate of either of these entities as a result of his minor investment in those companies.

There are no family relationships between any of the other Directors or executive officers of the Company.

There is no understanding or arrangement between any Director, officer or any other persons pursuant to which such individual was or is to be selected as a Director or officer of the Company.

Involvement in Certain Legal Proceedings

To the knowledge of management, during the past five years, no present or former director, executive officer, affiliate or person nominated to become a director or an executive officer of the Company:

(1)

Filed a petition under the federal bankruptcy laws or any state insolvency law, nor had a receiver, fiscal agent or similar officer appointed by a court for the business or property of such person, or any partnership in which he or she was a general partner at or within two years before the time of such filing, or any corporation or business association of which he or she was an executive officer at or within two years before the time of such filing;

(2)	Was convicted in a criminal proceeding or named the subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

(3)

Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him or her from or otherwise limiting his or her involvement in any type of business, commodities, securities or banking activities;

(4)

Was found by a court of competent jurisdiction in a civil action or by the SEC or the Commodity Futures Trading Commission (“CFTC”) to have violated any federal or state securities law or Federal commodities law, and the judgment in such civil action or finding by the SEC or CFTC has not been subsequently reversed, suspended, or vacated.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who beneficially own more than 10% of the Company’s Common Stock to file initial reports of ownership and reports of changes in ownership with SEC. In fiscal 2004, Robert M. Carter, President of TPC, the Company’s wholly-owned subsidiary, failed to timely file one Form 4 Report involving one transaction. Clarke H. Bailey, John A. Clendening and Neal F. Harding, Directors of the Company, recently each filed a Form 5 Report which indicated they failed to file one Form 4 Report for fiscal 2004 involving one transaction each.

Code of Ethics

The Company’s Board of Directors has adopted a Code of Ethics that applies to the Company’s Chief Executive Officer, financial officers and executive officers, including its

President and Chief Financial Officer. A copy of this Code of Ethics can be found at the Company’s internet website at www.Tengasco.com. The Company intends to disclose any amendments to its Code of Ethics, and any waiver from a provision of the Code of Ethics granted to the Company’s Chief Executive Officer, President, Chief Financial Officer, or persons performing similar functions, on the Company’s Internet website within five business days following such amendment or waiver. The information contained on or connected to the Company’s Internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that the Company files with or furnishes to the SEC.

ITEM 11 EXECUTIVE COMPENSATION

The following table sets forth a summary of all compensation awarded to, earned or paid to, the Company’s Chief Executive Officer during fiscal years ended December 31, 2004, December 31, 2003 and December 31, 2002. None of the Company’s other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity during those periods.

Summary Compensation Table

				-----------Long Term Awards---------------
	Annual Compensation			-------Awards--------
Name and Principal Position	Year	Salary ($)		Bonus ($)	Other Annual Compensation	Restricted ($Stock Awards($)	Securities Underlying Options/ SARs(#)¹⁰		Payouts	All Other Compensation
Richard T. Williams,	2004	$	80,000	$-0-	$-0-	-0-		13,125	-0-	-0-
Chief Executive Officer	2003	$	80,000	$-0-	$-0-	-0-		73,125	-0-	-0-

Malcolm E. Ratliff,	2002	$	80,000	$-0-	$1,000	-0-		52,500	-0-	-0-
Chief Executive Officer¹¹

Option Grants For Fiscal 2004

No stock options or stock appreciation rights were granted during fiscal year

ended December 31, 2004 to the Chief Executive Officer. None of the Company’s other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity during the fiscal year ended December 31, 2004.

Aggregate Option Exercises For Fiscal 2004
and Year End Option Values

			Number of Securities Underlying Unexercised Options/SARs at December 31, 2004	Value¹² of Unexercised In-the-Money Options/SARs at December 31, 2003
Name	Shares Acquired on Exercise	Value ($) Realized¹³	Exercisable/ Unexercisable	Exercisable/ Unexercisable
Richard T. Williams	50,000	$8,500	-0-/-0-	-0-

None of the Company’s other executive officers earned compensation in excess of $100,000 per annum for services rendered to the Company in any capacity.

The Company adopted an employee health insurance plan in August 2001. The Company does not presently have a pension or similar plan for its directors, executive officers or employees. Management has considered adopting a 401(k) plan and full liability insurance for directors and executive officers. However, there are no immediate plans to do so at this time.

Compensation of Directors

The Board of Directors has resolved to compensate members of the Board of Directors for attendance at meetings at the rate of $250 per day, together with direct out-of-pocket expenses incurred in attendance at the meetings, including travel. The Directors, however, have waived such fees due to them as of this date for prior meetings.

Members of the Board of Directors may also be requested to perform consulting or other professional services for the Company from time to time. The Board of Directors has reserved to itself the right to review all directors’ claims for compensation on an ad hoc basis.

Directors who are on the Company’s Audit, Compensation/Stock Option and Nomination and Goverance Committees are independent and therefore, do not receive any consulting, advisory or compensatory fees from the Company. However, such Board members may receive fees from the Company for their services on those committees. On December 28, 2004, the Company issued 100,000 shares of restricted shares of its common stock each to Clarke H. Bailey and John A. Clendening and 50,000 shares of restricted stock to Neal F. Harding who are Directors of the Company for their services as members of the Company’s Audit Committee. The Company intends to implement a plan for the payment of those committee members for their services on an annual basis.

Employment Contracts

The Company had entered into an employment contract with its Chief Executive Officer, Richard T. Williams for a period of two years through December 31, 2004 at an annual salary of $80,000. Dr. Williams resigned as Chief Executive Officer of the Company at the expiration of his employment contract. There are presently no other employment contracts relating to any member of management. However, depending upon the Company’s operations and requirements, the Company may offer long term contracts to directors, executive officers or key employees in the future.

Compensation Committee Interlocking
And Insider Participation

There are no interlocking relationships between any member of the Company’s Compensation Committee and any member of the compensation committee of any other company, nor has any such interlocking relationship existed in the past. No member of the Compensation Committee is or was an officer or an employee of the Company during the past three years.

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

Security Ownership of Certain Beneficial Owners

The following tables set forth the share holdings of the Company’s directors and executive officers and those persons who own more than 5% of the Company’s common stock as of March 15, 2005 with these computations being based upon 48,927,828 shares of common stock being outstanding as of that date and as to each shareholder, as it may pertain, assumes the exercise of options or warrants or the conversion of preferred stock granted or held by such shareholder as of March 15, 2005.

Five Percent Stockholders¹⁴

Name and Address	Title	Number of Shares Beneficially Owned	Percent of Class
Dolphin Offshore	Stockholder	16,540,140¹⁵	33	.7%
Partners, L.P.
129 East 17th Street
New York, NY 10003
SC Fundamental Value	Stockholder	4,822,600¹⁶	9	.9%
Fund, L.P.
747 Third Avenue, 27th Fl.
New York, NY 10017

Directors and Officers¹⁷

Name and Address	Title	Number of Shares Beneficially Owned	Percent of Class
Clarke H. Bailey	Director	100,000¹⁸	Less than 1%
1865 Palmer Avenue
Larchmont, NY 10538
Jeffrey R. Bailey	Director;	149,412¹⁹	Less than 1%
2306 West Gallaher Ferry	President
Knoxville, TN 37932
John A. Clendening	Director	200,000²⁰	Less than 1%
1031 Saint Johns Drive
Maryville, TN 37801
Neal F. Harding	Director	685,180²¹	1.4
2509 Plantside Drive
Louisville, KY 40299
Carlos P. Salas	Director	None	0
129 East 17th Street
New York, NY 10003
Peter E. Salas	Director	16,540,140²²	33.8
129 East 17th Street
New York, NY 10003
Richard T. Williams	Director	263,125²³	Less than 1%
4477 Deer Run Drive Louisville, TN

Name and Address	Title	Number of Shares Beneficially Owned	Percent of Class
Robert M. Carter	President	20,821²⁴	Less than 1%
441 Glen Abbey Blvd.	Tengasco
Knoxville, TN 37922	Pipeline Corporation
Mark A. Ruth	Chief	69,287²⁵	Less than 1%
9400 Hickory Knoll Lane	Financial
Knoxville, TN 37931	Officer
Cary V. Sorensen	Vice-	47,875²⁶	Less than 1%
5517 Crestwood Drive	President; General
Knoxville, TN 37919	Counsel; Secretary
All Officers, Directors		18,075,840²⁷	36.7
and Director-Nominees as a group

Changes in Control

Except as indicated below, to the knowledge of the Company’s management, there are no present arrangements or pledges of the Company’s securities which may result in a change in control of the Company.

Equity Compensation Plan Information

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding, options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation
plans approved by
security holders²⁸	295,153	$1.26	704,847

Equity compensation
plans not approved
by security holders	0	N/A	0

Total	295,153	$1.26	704,847

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with Management and Others

Except as set forth hereafter, there have been no material transactions, series of similar transactions or currently proposed transactions during 2004, to which the Company or any of its subsidiaries was or is to be a party, in which the amount involved exceeds $60,000 and in which any director or executive officer or any security holder who is known to the Company to own of record or beneficially more than 5% of the Company’s common stock, or any member of the immediate family of any of the foregoing persons, had a material interest.

The Company’s Board of Directors has not adopted any general policy with respect to these transactions, many of which were effected on behalf of the Company by senior management prior to consideration of the transaction by the Board of Directors in light of senior management’s perceived urgency of the funding requirements, the availability of alternative sources and the terms of such transactions were at least as favorable to the Company as could have been obtained through arms-length negotiations with unaffiliated third parties. In each of the loans to the Company by Dolphin Offshore Partners, L.P. (“Dolphin), which owns more than ten percent of the Company’s outstanding Common Stock and whose general partner, Peter E. Salas, is a Director of the Company, Mr. Salas negotiated with on behalf of Dolphin with senior

management of the Company as to the terms thereof and did not participate in any Board action with respect thereto.

On February 2, 2004, Dolphin loaned the Company the sum of $225,000 which was used for making payment of principal and interest to Bank One for February, 2004. This loan was evidenced by a promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable on April 4, 2004. The obligations under the loan were secured by an undivided interest in the Company’s Tennessee and Kansas pipelines.

In March, 2004, net proceeds from the Company’s Rights Offering in the amount of $3,850,000 were used to pay the principal amount plus accrued indebtedness owed by the Company to Dolphin for all loans previously made by Dolphin to the Company, including the loan made on February 2, 2004 described above.

The following table sets forth the number of shares of Common Stock purchased in connection with the Rights Offering by persons who at the time were either Directors and Officers of the Company or owners of more than ten percent of the Company’s outstanding Common Stock.

Name	Position	Shares Purchased
Stephen W. Akos	Director	48,868
Jeffrey R. Bailey	Director; President	66,287
John A. Clendening	Director	75,000
Robert L. Devereux	Director	412,457	²⁹
Richard T. Williams	Director; Chief Executive Officer	190,000

Dolphin Offshore Partners, L.P.³⁰		14,248,	732³¹

On May 18, 2004, 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 18, 2005. This loan is secured by a first lien on the Company’s Tennessee and Kansas

producing properties and the Tennessee pipeline. The proceeds of this loan were used to fund in part the Company’s settlement of its litigation with Bank One.

On December 28, 2004, Neal F. Harding, a Director of the Company, pursuant to the offering made to all Series A shareholders exchanged all of his 1,985 Series A Shares for 4.48 units in the Company’s Kansas drilling program. See, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operation” — “Liquidity and Capital Resources.”

On December 30, 2004 Dolphin loaned the Company $550,000 bearing interest at 12% per annum with interest payable quarterly and principal payable on May 20, 2005. This loan is secured by a first lien on the Company’s Tennessee and Kansas producing properties and the Tennessee pipeline. The proceeds of this loan were used to fund in part the Company’s exchange of cash for a portion of the Company’s outstanding Series A Shares.

On March 4, 2005, the Company sold its gas wells, associated gathering system, underlying leases and rights of way located on its Kansas Properties for $2.4 million. The net proceeds from the sale were used to pay down the Company’s note to Dolphin dated May 18, 2004 from its original amount of $2,500,000 to $150,000.

Indebtedness of Management

No officer, director or security holder known to the Company to own of record or beneficially more than 5% of the Company’s common stock or any member of the immediate family of any of the foregoing persons is indebted to the Company.

Parent of the Issuer

The Company has no parent.

ITEM 14 PRINCIPAL ACCOUNTANTS FEES AND SERVICES

The following table presents the fees for professional audit services rendered by BDO Seidman, LLP for the audit of the Company’s annual consolidated financial statements for the fiscal years ended December 31, 2004 and December 31, 2003, and fees for other services rendered by BDO Seidman, LLP during those periods:

Fee Category	Fiscal 2004	Fiscal 2003
Audit Fees	$155,000	$209,310
Audit-Related Fees	$ 0	$ 0
Tax Fees	$ 0	$ 0
All Other Fees	$ 12,000	$ 7,250
Total Fees	$167,000	$216,560

Audit fees include fees related to the services rendered in connection with the annual audit of the Company’s consolidated financial statements, the quarterly reviews of the Company’s quarterly reports on Form 10-Q and the reviews of and other services related to registration statements and other offering memoranda. The audit fees in 2004 were substantially less than in 2003 due to the settlement of the Company’s litigation with Bank One in May 2004

Audit-related fees are for assurance and related services by the principal accountants that are reasonably related to the performance of the audit or review of the Company’s financial statements.

Tax Fees include (i) tax compliance, (ii) tax advice, (iii) tax planning and (iv) tax reporting.

All Other Fees includes fees for all other services provided by the principal accountants not covered in the other categories such as litigation support, etc. In 2004, the amount of fees in this category were higher than in 2003 due to fees for services performed by BDO Seidman, LLP in connection with the Company’s filling of a registration statement on Form S-1 with the SEC for the Rights Offering which offering was completed in March 2004.

All of the services for 2003 and 2004 were performed by the full-time, permanent employees of BDO Seidman, LLP

All of the 2004 services described above were approved by the Audit Committee pursuant to the SEC rule that requires audit committee pre-approval of audit and non-audit services provided by the Company’s independent auditors to the extent that rule was applicable during fiscal year 2004. The Audit Committee has considered whether the provisions of such services, including non-audit services, by BDO Seidman, LLP is compatible with maintaining BDO Seidman, LLP’s independence and has concluded that it is.

PART IV

ITEM 15 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:

2. 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)
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)
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


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)
14	Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant's annual report on Form 10-K filed March 30, 2004)
21	List of subsidiaries (Incorporated by reference to Exhibit 21 to the registrant's annual report on Form 10-K filed March 31, 2003 (the "2002 Form 10-KSB"))
23.1*	Consent of Ryder Scott Company, L.P.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)

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

* Exhibit filed with this Report

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: March 31, 2005


TENGASCO, INC. (Registrant)
By: s/Jeffrey R. Bailey Jeffrey R. Bailey, President
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 30, 2005
Clarke H. Bailey
s/Jeffrey R. Bailey	Director;	March 30, 2005
Jeffrey R. Bailey	President
s/John A. Clendening	Director	March 30, 2005
John A. Clendening
s/Neal F. Harding	Director	March 30, 2005
Neal F. Harding
s/Carlos P. Salas	Director	March 30, 2005
Carlos P. Salas
s/Peter E. Salas	Director	March 30, 2005
Peter E. Salas
s/Richard T. Williams	Director	March 30, 2005
Richard T. Williams
s/Mark A. Ruth	Principal Financial	March 30, 2005
Mark A. Ruth	and Accounting Officer

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.

Although the actual total cost of production for the Swan Creek Field in 2004 as compared to 2003 remained constant, the cost per BOE increased substantially because of an approximate 43% decrease in production of oil and gas.

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.

⁴

With respect to the pipeline facilities, during the years ended December 31, 2000 and 1999, this included portions which were under construction.

⁵

No cash dividends have been declared or paid by the Company for the periods presented.

⁶

On July 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150 under which mandatorily redeemable preferred stock shall be reclassified at estimated fair value to a liability. Thus, in 2003, it was determined that each of the Company’s series of preferred stock qualifies as shares subject to mandatory redemption and should be classified as a liability. Also, see Note 9 to the Consolidated Financial Statements in Item 8 of this Report.

⁷

See, Note 7 to Consolidated Financial Statements in Item 8 of this Report.

⁸

See, Note 8 to Consolidated Financial Statements in Item 8 of this Report.

⁹

See, Note 9 to Consolidated Financial Statements in Item 8 of this Report.

¹⁰

Number of shares underlying options has been retroactively adjusted for a 5% stock dividend declared by the Company as of September 4, 2001.

¹¹

Malcolm E. Ratliff served as the Company's Chief Executive Officer throughout 2002. Richard T. Williams replaced Mr. Ratliff as Chief Executive Officer on February 3, 2003 and continued in that position until he resigned as of December 31, 2004.

¹²

Unexercised options are in-the-money if the fair market value of the underlying securities exceeds the exercise price of the option. The fair market value of the Common Stock was $0.26 per share on December 31, 2004, as reported by The American Stock Exchange. Prior to his becoming Chief Executive Officer of the Company. Dr. Williams on August 5, 2002 was granted an option to purchase 13,125 shares of the Company’s common stock at a price of $2.69 per shares. That option expires on August 4, 2005. Since the exercise price of shares underlying that option had a negative value as of December 31, 2004 they are not included in this chart.

¹³

Value realized in dollars is based upon the difference between the fair market value of the underlying securities on the date of exercise, and the exercise price of the option. On February 25, 2004, Dr. Williams exercised his option to the extent of purchasing 50,000 shares of the Company’s common stock at $0.50 per share. The closing price of the Company’s common stock on February 25, 2004 as reported on by the American Stock Exchange was $0.67 per share.

¹⁴

Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table reflect shares issued in connection with the Company’s Rights Offering completed in 2004.

¹⁵

Consists of 16,244,452 shares held directly by Dolphin Offshore Partners, L.P. (“Dolphin”) of which Peter E. Salas, a Director of the Company, is the controlling person; a warrant held by Dolphin to purchase 10,500 shares at $7.98 per share; 117,188 shares underlying 9,000 shares of the Company’s Series B 8% Cumulative Convertible Preferred Stock held directly by Dolphin; and, 168,000 shares held directly by Peter E. Salas.

¹⁶

Ownership of shares reported on Schedule 13F filed with the SEC by member of a group consisting of SC Fundamental Value Fund , L.P., SC Fundamental LLC, SC-BVI Partners, PMC-BVI, Inc., SC Fundamental Value BVI, Inc., Peter M. Collery and Neil H. Koffler.This group initially reported its ownership on a Schedule 13G filed with the SEC.

¹⁷

Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of March 15, 2005 and reflect the results of the Company’s Rights Offering to shareholders of record February 27, 2004.

¹⁸

Consists of shares held directly.

¹⁹

Consists of 76,287 shares held directly and an option to purchase 73,125 shares.

²⁰

Consists of shares held directly.

²¹

Consists of shares held directly.

²²

Consists of 168,000 shares held directly, 16,244,452 shares held directly by Dolphin Offshore Partners, L.P. (“Dolphin”) of which Peter E. Salas is the controlling person; a warrant held by Dolphin to purchase 10,500 shares at $7.98 per share; and, 117,188 shares underlying 9,000 shares of the Company’s Series B 8% Cumulative Convertible Preferred Stock held by Dolphin which is convertible into the Company’s Common Stock.

²³

Consists of 250,000 shares held directly and options to purchase 13,125 shares.

²⁴

Consists of 7,696 shares held directly and options to purchase 13,125 shares.

²⁵

Consists of 100 shares held directly and options to purchase 69,187shares.

²⁶

Consists of shares underlying options.

²⁷

Consists of shares held directly and indirectly by management, shares held by Dolphin, 216,437 shares underlying options, 10,500 shares underlying warrants and 117,188 shares underlying convertible preferred stock.

²⁸

Refers to Tengasco, Inc. Stock Incentive Plan

²⁹

Consists of 352,012 shares purchased directly with his spouse and 60,445 shares purchased by a limited liability company. The shares purchased by the limited liability company have been adjusted to reflect Mr. Devereux’s beneficial ownership interest in the shares purchased by the limited liability company.

³⁰

Peter E. Salas, a Director of the Company, is the general partner and controlling person of Dolphin Offshore Partners, L.P.

³¹

Consists of 14,104,732 shares purchased directly by Dolphin Offshore Partners, L.P. and 144,000 shares purchased by Peter E. Salas.

Tengasgo,Inc.
and Subsidiaries

Consolidated Financial Statements
Years Ended December 31, 2004, 2003 and 2002

Tengasco, Inc.and
Subsidiaries

Consolidated Financial StatementsYears
Ended December 31, 2004, 2003 and 2002

Report of Independent Registered Public Accounting Firm	F-3
Consolidated Financial Statements
Consolidated Balance sheets	F-4 - F-5
Consolidated Statements of loss	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-34

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, 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

F-3

Tengasco, Inc. and Subsidiaries

Consolidated Balance Sheets

December 31,	2004		2003
Assets (Note 1)
Current
Cash and cash equivalents	$	267,735	$	312,666
Investments		--		60,000
Accounts receivable		706,752		508,378
Participant receivables		73,016		68,402
Inventory		341,745		280,693
Deferred loan fees, net of accumulated
amortization of $518,166 and $367,030		--		151,136
Other current assets		67,526		223,003

Total current assets		1,456,774		1,604,278
Oil and gas properties, net (on the basis
of full cost accounting) (Notes 4 and 18)		12,826,903		12,989,443
Pipeline facilities, net of accumulated
depreciation of $1,812,204 and $1,265,003 (Note 5)		14,602,639		15,139,789
Other property and equipment, net (Note 6 )		323,433		870,730

	$	29,209,749	$	30,604,240

F-4

December 31,
2004
2003

Liabilities and Stockholders’ Equity (Note 1)

Current liabilities

Current maturities of long-term debt (Note 7) $ 26,672 $ 6,127,290

Accounts payable 319,820 1,075,948

Accrued interest payable 25,367 234,321

Other accrued liabilities 211,622 18,560

Notes payable to related parties (Note 3) 3,050,000 3,709,000

Drilling program (Note 9) 1,316,702 --

   Current shares subject to mandatory redemption (Note 9) 3,260,312 1,261,876

Total current liabilities 8,210,495 12,426,995

Shares subject to mandatory redemption (Note 9) 1,395,301 6,035,183

Drilling program (Note 9) 438,901 --

Asset retirement obligations (Note 10) 708,677 668,556

Long term debt, less current maturities (Note 7) 106,688 221,635

Total liabilities 10,860,062 19,352,369

Commitments and Contingencies (Notes 5, 7, 8, and 10)

Stockholders' equity (Note 11)

   Common stock, $.001 par value; authorized 100,000,000 shares;

   48,756,977 and 12,064,977 shares issued and outstanding 48,757 12,080

   Additional paid-in capital 51,686,454 42,721,290

   Accumulated deficit (33,385,524 ) (31,391,499 )

   Accumulated other comprehensive loss -- (90,000 )

Total stockholders' equity 18,349,687 11,251,871

$ 29,209,749 $ 30,604,240

See accompanying notes to consolidated financial statements.

F-5

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Loss

Years ended December 31,	2004			2003			2002

Revenues and other income
Oil and gas revenues	$	6,013,374		$	6,040,872		$	5,437,723
Pipeline transportation revenues		92,599			163,393			259,677
Interest Income		3,501			985			3,078

Total revenues and other income		6,109,474			6,205,250			5,700,478

Costs and expenses
Production costs and taxes		3,364,429			3,412,201			3,094,731
Depreciation, depletion and amortization
(Notes 4, 5 and 6)		2,067,566			2,308,007			2,413,597
General and administrative		1,177,183			1,486,280			1,868,141
Interest expense (Notes 9, 10 and 13)		1,367,180			1,120,738			578,039
Public relations		35,347			31,183			193,229
Professional fees		779,180			549,503			707,296
Loss on impairment of long-lived asset		--			495,000			--
Loss on sale of equipment, net		107,744			--			--

Total costs and expenses		8,898,629			9,402,912			8,855,033

Operating loss		(2,789,155	)		(3,197,662	)		(3,154,555	)
Gain from extinguishment of debt (Note 16)		336,820			--			--
Gain on Preferred Stock (Note 9)		458,310			--			--

Net loss		(1,994,025	)		(3,197,662	)		(3,154,555	)
Dividends on preferred stock (Note 9)		--			(268,389	)		(506,789	)

Net loss attributable to common stockholders before
cumulative effects of a changes in accounting principle		(1,994,025	)		(3,466,051	)		(3,661,344	)
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 loss attributable to common stockholders	$	(1,994,025	)	$	(3,451,580	)	$	(3,661,344	)

Net loss attributable to common stockholders per shares
Basic and diluted:
Operations	$	(0.05	)	$	(0.29	)	$	(0.33	)

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	$	(0.05	)	$	(0.29	)	$	(0.33	)


Weighted average shares outstanding		40,855,972			11,956,135			11,062,436

See accompanying notes to consolidated financial statements

F-6

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity and
Comprehensive Losses for the years ending
December 31, 2004, 2003 and 2002

	Common Stock				Paid-In Capital			Accumulated Deficit			Comprehensive Loss			Accumulated Other Comprehensive Income (Loss)			Treasury Stock Shares			Amount			Total
	Shares		Amount		Paid-In Capital			Accumulated Deficit			Comprehensive Loss			Accumulated Other Comprehensive Income (Loss)			Treasury Stock Shares			Amount			Total

Balance, December 31, 2001		10,560,605	$	10,561	$	39,242,555		$	(24,115,382	)	$	—		$	—			14,500		$	(145,887	)	$	14,991,847
Net loss		—		—		—			(3,154,555	)		—			—			—			—			(3,154,555	)
Comprehensive loss:
Net loss		—		—		—			—			(3,154,555	)		—			—			—			—
Other comprehensive loss		—		—		—			—			(115,500	)		(115,500	)		—			—			(115,500	)
2002 comprehensive loss		—		—		—			—			(3,270,055	)		—			—			—			—
Common stock issued in private placements, net of related expenses		850,000		850		2,676,150			—						—			—			—			2,677,000
Common stock issued on conversion of debt		20,592		20		119,980			—			—			—									120,000
Common stock issued in purchase of equipment		19,582		20		149,980			—			—			—			—			—			150,000
Common stock issued for services		8,500		9		48,611						—			—			—			—			48,620
Dividends on convertible redeemable preferred stock		—		—		—			(506,789	)														(506,789	)


Balance, December 31, 2002		11,459,279		11,460		42,237,276			(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 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		12,064,977		12,080		42,721,290			(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		48,756,977	$	48,757	$	51,686,454		$	(33,385,524	)	$	—		$	—			—		$	—		$	18,349,687

See accompanying notes to consolidated financial statements

F-7

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

Years ended December 31,	2004			2003

Operating activities Net loss	$	(1,994,025	)	$	(3,197,662)		$(3,154,555)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		2,067,566			2,308,007		2,413,597
Compensation and services paid in stock options, stock
warrants, and common stock		82,500			203,812		48,620
Loss on impairment of long-lived assets		--			495,000		--
Accretions of liabilities		825,371			459,691		--
Loss (gain) on sale of equipment, net		99,456			(13,103	)	--
Loan fee amortization		107,956			--		--
Gain on extinguishment of debt		(336,820	)		--		--
Gain on exchange of preferred stock		(458,310	)		--		--
Realized loss on investment		150,000			--		--
Changes in assets and liabilities:
Accounts receivable		(198,374	)		222,289		(69,192	)
Participant receivables		(4,614	)		2,203		13,492
Inventory		(61,052	)		(17,945	)	(103,384	)
Other assets		155,477			14,613		58,000
Accounts payable - trade		(756,129	)		(320,813	)	188,597
Accrued interest payable		(208,954	)		173,179		7,003
Other accrued liabilities		193,062			(13,244	)	31,805
Asset retirement obligation		(33,247	)		--		--

Net cash (used in) provided by operating activities		(370,137	)		316,027		(566,017	)


Investing activities
Additions to other property & equipment	(40,815	)	--		--
(Increases) decreases to other property and equipment	296,865		--		(214,897	)
Net additions to oil and gas properties	(1,122,903	)	(133,501	)	(1,982,529	)
Additions to pipeline facilities	(10,001	)	(5,775	)	(841,750	)
Decrease in restricted cash	--		--		120,872
Other	--		74,207		28,367

Net cash used in investing activities	(876,854	)	(65,069	)	(2,889,937	)

Financing activities
Proceeds from exercise of options	71,000		47,000		--
Proceeds from borrowings	3,310,815		3,256,171		2,063,139
Repayments of borrowings	(9,848,560	)	(3,432,470	)	(2,378,273	)
Proceeds from issuance of common stock	8,848,341		250,000		2,677,000
Proceeds from private placements of convertible
redeemable preferred stock, net	--		--		1,303,168
Dividends paid on preferred stock	(456,166	)	(20,120	)	(364,858	)
Exchange of Series A preferred stock for cash (Note 9)	(723,370	)	--		--
Payment of loan and offering fees	--		(223,003	)	(53,543	)

F-8

Net cash provided by (used in) financing activities 1,202,060 (122,422 ) 3,246,633



Net change in cash and cash equivalents (44,931 ) 128,536 (209,321 )



Cash and cash equivalents, beginning of year 312,666 184,130 393,451



Cash and cash equivalents, end of year $ 267,735 $ 312,666 $ 184,130

Supplemental disclosure of non-cash investing and

   financing activities:

     Issuance of common stock on conversion of debt -- $ 69,549 $ 120,000

     Issuance of common stock and stock options for

          services received and charitable contributions made -- $ 203,812 $ 48,620

     Purchase of equipment by issuing common stock -- - $ 150,000

     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 Subsidiaries

Notes to Consolidated Financial Statements

1. Going Concern
Uncertainty

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. The Company has incurred continuous losses through these operating stages and has an accumulated deficit of $33,385,524 and a working capital deficit of $6,753,721 as of December 31, 2004. During 2002, the Company was informed by its primary lender (Bank One) that the entire amount of its outstanding credit facility was immediately due and payable, as provided for in the Credit Agreement. The amount due to its primary lender amounted to approximately $5.1 million and was classified as a current liability as of December 31, 2003. The Company disputed its obligation to make this payment and has resolved the dispute as discussed in Note 16 to the Consolidated Financial Statements. The Company also has significant redemption amounts due to be satisfied in 2005 related to its Mandatorily Redeemable Series B Preferred Shares (see Note 9). These circumstances raise substantial doubt about the Company’s ability to continue as a going concern.

Management’s plans include the continuation of its drilling efforts. The Company plans to drill wells in new locations it has identified in Kansas on its existing leases in response to drilling activity in the area establishing new areas of oil production. The Company successfully drilled the Dick No. 7 well in Kansas in 2001 and completed the well as an oil well, however it was not able to drill any new wells in Kansas in 2002 or 2003 due to lack of funds available for such drilling caused by the Bank One situation. In September 2004, the Company drilled and completed the Lewis No. 3 well in Kansas using only funds from the proceeds of the Company’s ongoing operations. By using the Company’s own funds, it was not necessary to permit any third party to either participate in financing of drilling or to acquire any interest in the well. The Company receives all proceeds of production attributable to the working interest in the Lewis No.3 well. The Company is hopeful now that the Bank One matter has been resolved that it will be able to perform additional drilling and well workovers in Kansas to maximize production from the Kansas Properties. The Company is also pursuing additional bank financing on terms that it finds satisfactory and is considering means to meet its required redemption on its preferred stock in 2005. However, the inability of the Company to obtain long-term financing could impair the Company’s ability to meet its obligations as they come due.

2. 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

F-10

Deposit Mining and Milling Policies Company. The Company subsequently changed its name to Onasco Companies, Inc.

The Company changed its domicile from the State of Utah to the State of Tennessee on May 5, 1995 and its name was changed from “Onasco Companies, Inc.” to “Tengasco, Inc.”

The Company’s principal business consists of oil and gas exploration, production and related property management in the Appalachian region of eastern Tennessee and in the state of Kansas. The Company’s corporate offices are in Knoxville, Tennessee. The Company operates as one reportable business segment, based on the similarity of activities.

During 1996, the Company formed Tengasco Pipeline Corporation (“TPC”), a wholly-owned subsidiary, to manage the construction and operation of a 65-mile gas pipeline as well as other pipelines planned for the future. During 2001, TPC began transmission of natural gas through its pipeline to customers of Tengasco.

Basis of Presentation

The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation and Tennessee Land and Mineral, Inc. All significant intercompany balances and transactions have been eliminated.

Use of Estimates

The accompanying financial statements are prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The actual results could differ from those estimates.

Revenue Recognition

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.

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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 closing oil and gas wells. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs.

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

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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) The Company has adopted a 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 2004, 2003 or 2002.

Pipeline Facilities

Phase I of the pipeline was completed during 1999. Phase II of the pipeline was completed on March 8, 2001. Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years; beginning at the time it was placed in service.

Other Property and Equipment and Long — Lived Assets

Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from five to ten years. Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value. At December 31, 2004, 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.

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Stock-Based Compensation

SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), was implemented in January 1996. As permitted by SFAS 123, the Company has continued to account for stock compensation to employees by applying the provisions of Accounting Principles Board Opinion No. 25. If the accounting provisions of SFAS 123 had been adopted, net loss and loss per share would have been as follows for the years ended December 31, 2004, 2003 and 2002.

	2004		2003		2002
Net loss attributable to common shareholders
As reported	$ (1,994,025	)	$(3,451,580	)	$(3,661,344	)
Stock based compensation	--		(22,650	)	(77,821	)
Pro forma	$ (1,994,025	)	$(3,474,230	)	$(3,739,165	)

Basic and diluted loss per share
As reported	$ (0.05)		$ (0.29	)	$ (0.33	)
Pro forma	$ (0.05)		$ (0.29	)	$ (0.34	)

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, 2004 and 2003 is necessary. However, actual write-offs may occur.

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Income Taxes

The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss 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.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At times, such cash in banks is in excess of the FDIC insurance limit.

The Company’s primary business activities include oil and gas sales to several customers in the states of Tennessee and Kansas. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry. The Company 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.

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 of natural gas sales. Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Company’s projected results of operations.

Loss per Common Share

Basic loss per share is computed by dividing loss available to common shareholders by the weighted average number of shares outstanding during each year. Shares issued during the year are weighted for the portion of the year that they were outstanding. Diluted loss per share does not differ from basic loss per share since the effect of all common stock equivalents is anti-dilutive. Basic and diluted loss per share are based upon 40,855,972 weighted average common shares outstanding for the year ended December

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31, 2004; 11,956,135 weighted average common shares outstanding for the year ended December 31, 2003; and 11,062,436 weighted average common shares outstanding for the year ended December 31, 2002. Diluted loss per share does not consider approximately 0, 390,278 and 1,473,000 potential weighted average common shares for 2004, 2003, and 2002 related primarily to common stock options and convertible preferred stock and debt. These shares were not included in the computation of the diluted loss per share amount because the Company was in a net loss position and, thus, any potential common shares were anti-dilutive to the loss per share calculation.

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 March 2004, The Emerging Issues Task Force (“EITF”) reached a consensus that mineral rights, as defined in EITF Issue No. 04-02, “Whether Mineral Rights are Tangible or Intangible Asset,” are tangible assets and that they should be removed as examples of intangible assets in SFAS Nos. 141 and 142. The Financial Accounting Standards Board (FASB) has recently ratified this consensus and directed the FASB staff to amend SFAS Nos. 141 and 142 through the issuance of FASB Staff Positions FSP FAS 141-1 and FSP FAS 142-1. Historically the Company has included the cost of such mineral rights as tangible assets, which is consistent with the EITF’s consensus. As such, EITF 04-02 will not affect Tengasco’s consolidated condensed financial statements.

Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), by oil and gas producing companies following the full cost accounting method was issued in September 2004. (“SAB 106”) provided an interpretation of how a company, after adopting SFAS 143, should compute the full cost ceiling to avoid double-counting the expected future cash outflows associated with asset retirement costs. The provisions of this interpretation has been applied by the Company and adoption of this bulletin has no impact on the financial statements.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”). This Statement is a revision to SFAS No. 123, and supersedes APB Opinion No. 25, “Accounting for Stock Issued to

F-16

Employees.” This Statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services, primarily focusing on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. Companies will be required to measure the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service, the requisite service period (usually the vesting period), in exchange for the award. The grant date fair value of employee share options and similar instruments will be estimated using option-pricing models. If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modifications. SFAS 123R will be effective for periods beginning after June 15, 2005 and allows for several alternative transition methods. Accordingly, the Company will adopt SFAS 123R in its third quarter of fiscal 2005. The Company is currently evaluating the provisions of SFAS 123R and has not determined the impact that this statement will have on its results of operations or financial position.

3.Related Party
Transactions

From December 2002 through December 9, 2003, Dolphin Offshore Partners, L.P. (“Dolphin”) acquired a total of an 85% undivided interest in the Company’s Tennessee and Kansas pipelines as collateral for a series of seven loans. In the first five of these transactions totaling $1,650,000, 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 believes were at least as favorable to the Company as it could have obtained through arms-length negotiations with unaffiliated third parties. The Company’s Board approved the sixth and seventh loans on December 3 and 9, 2003 in the amounts of $225,000 and $250,000, respectively, with no participation by Mr. Salas in the meeting or the vote, which was unanimous by the seven other Directors present at the meeting. In addition, the Company entered into a continuing security agreement, which was approved by the Board with no participation by Mr. Salas in the meeting or vote, which was unanimous by the seven other Directors present at the meeting, providing the terms of Dolphin’s security interest collateralizing all of its loans.

On December 24, 2003, Dolphin loaned the Company the sum of $1,000,000 which was used for working capital and to pay all interest and principal in full of convertible loans to the Company then being held by

F-17

several persons. See Note 7 for the terms of such loans. This loan was evidenced by a separate promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable on April 4, 2004. The obligations under the loan were secured by an undivided interest in the Company’s Tennessee and Kansas pipelines and the security agreement referred to above.

On February 2, 2004, Dolphin loaned the Company the sum of $225,000 which was used for making payment of principal and interest to Bank One for February, 2004. This loan was evidenced by a separate promissory note bearing interest at the rate of 12% per annum, with payments of interest only payable quarterly and the principal balance payable on April 4, 2004. The obligations under the loan were secured by an undivided interest in the Company’s Tennessee and Kansas pipelines and the security agreement referred to above.

All notes payable to Dolphin dated prior to May 18, 2004 were repaid on March 30, 2004 from the proceeds received by the Company from its Rights Offering.

On May 18, 2004, 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 is 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.

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 is secured by the first lien on the Company’s Tennessee and Kansas properties and the Tennessee pipeline.

Amounts due to related parties consisted of the following:

December 31,
2004
2003

Unsecured note payable to a Director due

January 2004, with interest payable

quarterly at 8% per annum. Note is

convertible into common stock of the

Company at a rate of $2.88 per share of

common stock $ $ 500,000



Notes payable to a Director due with

interest payable quarterly at 12% per
annum. Notes are secured by the pipeline

   - 3,209,000



Notes payable to a Director due May 2005

with interest payable monthly at 12% per

annum. Notes are secured by Tennessee and

Kansas producing properties and the

pipeline 3,050,000 --

Total short term debt to related

parties      $3,050,000 $3,709,000

F-18

4.Oil and Gas
Properties

The following table sets forth information concerning the Company’s oil and gas properties:

December 31,	2004			2003
Oil and gas properties, at cost	$	18,703,077		$	17,580,174
Accumulation depreciation,
depletion and amortization		(5,876,174	)		(4,590,731	)

Oil and gas properties, net	$	12,826,903		$	12,989,443

During the years ended December 31, 2004 and 2003 the Company recorded depletion expense of approximately $1,285,443 and $1,388,000 respectively.

5.Pipeline Facilities

In 1996, the Company began construction of a 65-mile gas pipeline (1) connecting the Swan Creek development project to a gas purchaser and (2) enabling the Company to develop gas distribution business opportunities in the future. Phase I, a 30-mile portion of the pipeline, was completed in 1998. Phase II of the pipeline, the remaining 35 miles, was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company recorded approximately $547,161, $536,000, and $509,000 respectively in depreciation expense related to the pipeline for the years ended December 31, 2004, 2003 and 2002, respectively.

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.

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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	2004			2003
Machinery and equipment	5-7 yrs	$	778,930		$	1,392,190

Vehicles	5 yrs		410,493			490,367

Other	5 yrs		63,734			63,734

			1,253,157			1,946,291

Less accumulated depreciation			(929,724	)		(1,075,561	)

Other property and equipment - net		$	323,433		$	870,730

The Company uses the straight-line method of depreciation ranging from five years to thirty years, depending on the asset life.
For the year ended December 31, 2003, the Company recorded an impairment loss on equipment totaling $495,000.

7. Long Term Debt

Long-term debt to unrelated entities consisted of the following:

December 31,		2004	2003
Revolving line of credit with a bank,
due November 2004. The loan agreement
provides for increases or decreases to
the borrowing base as changes in proved
oil and gas reserves or other
production levels arise. Borrowings
bear interest at the bank's prime rate
plus 0.25%(4.25% at December 31,
2003). Collateralized by the oil and
gas properties and the related
operations and revenues. See Note 16.
Repaid May 18, 2004
	$	--	$ 5,101,777
Convertible notes payable to five
individuals; due January 2004, with
interest payable quarterly at 8% per
annum. Notes convertible into common
stock of the Company at a rate of $3.00
per share of common stock. Repaid March
24, 2004		--	650,000
Term loan payable to a Company; due May
1, 2004.Interest payable at 4.75%
Unsecured. Repaid March 31, 2004
		--	297,171
Note payable to a financial
institution, with $1,773 principal
payments due monthly beginning January
7, 2002 through December 7, 2006
Interest is payable monthly commencing
on January 7, 2002 at 7.5% per annum
Note is guaranteed by a major
shareholder and is collateralized by
certain assets of the Company
		39,399	57,004
Installment notes bearing interest at
the rate of 3.9% to 11.95% per annum
collateralized by vehicles and equipment
with monthly payments including interest
of approximately $10,000 due various
periods through 2006
		93,961	242,973

Total long-term debt		133,360	6,348,925
Less current maturities		(26,672)	(6,127,290)

Long-term debt, less current
maturities		$ 106,688	$ 221,635

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8. Commitments
and Contingencies

The Company is a party to lawsuits in the ordinary course of its business. While the damages sought in some of these actions are material, the Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have a material adverse effect in the aggregate on its financial statements.

In the ordinary course of business the Company has entered into various equipment and office leases which have remaining term of one year. Approximate future minimum lease payments to be made under non-cancelable operating leases in 2005 are $62,000.

Office rent expense was approximately $77,110, 78,830 and $84,000 for each of the three years ended December 31, 2004, respectively.

9. Cumulative
Convertible
Redeemable
Preferred Stock

The Company is authorized to create and has issued various classes of preferred stock (Series A, Series B and Series C). Shares of both Series A and B of Preferred Stock are immediately convertible into shares of Common Stock. Each $100 liquidation preference share of preferred stock is convertible at a rate of $7.00 for the Series A per share of common stock. For the Series B, the conversion rate is the average market price of the Company’s common stock for 30 days before the sale of the Series B preferred stock with a minimum conversion price of $9.00 per share. The conversion rate is subject to downward adjustment for certain events. The conversion prices have been adjusted prospectively for stock dividends and splits.

The holders of both the Series A and Series B Preferred Stock are entitled to a cumulative dividend of 8% per quarter. However, the payment of the dividends on the Series B Preferred Stock is subordinate to that of the Series A Preferred Stock. In the event that the Company does not make any two of six consecutive quarterly dividend payments, the holders of the Series A Preferred Stock have the right to appoint those directors which would constitute of majority of the Board of Directors. In such a scenario, the holders of the Preferred Shares would be entitled to elect a majority of the Board of Directors until all accrued and unpaid dividends have been paid.

The Company may redeem both of the Series A and B Preferred Shares upon payment of $100 per share plus any accrued and unpaid dividends. Further, with respect to the Series A Preferred Stock, commencing on October 1, 2003 and at each quarterly date thereafter while the Series A Preferred Stock is outstanding, the Company is required to redeem one-twentieth of the maximum number of Series A Preferred Stock outstanding. With respect to the Series B Preferred Stock, on the fifth anniversary after issuance (September, 2005), the Company is required to redeem all outstanding Series B Preferred Stock.

During 2002, the Board of Directors authorized the sale of up to 50,000 shares of Series C Preferred Stock at $100 per share. The Company issued 14,491 shares, resulting in net proceeds after commissions of $1,303,168. The Series C Preferred Stock accrue a 6% cumulative dividend on the outstanding balance, payable quarterly. These dividends are subordinate to the dividends payable to the Series A and Series B Preferred Stock holders. This stock is convertible into the Company’s common stock at the average stock trading price 30 days prior to the closing of the sales of all the Series C Preferred Stock being offered or $5.00 per share, whichever is greater. The Company is required to redeem any remaining Series C Preferred Stock and any accrued and unpaid dividends in May 2007.

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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. The Company has dividends in arrears as of December 31, 2004 and 2003 of $649,692 and $600,738.

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 the cash exchange option, and the face amount of $1,085,000 of Series A shares was exchanged on or before December 31, 2004 for 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 the 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

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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 has remaining only one Series A shareholder, in face amount of $200,000.

Future mandatory redemption requirements related to the remaining Series A, B and C Preferred Stock, as of December 31, 2004 are as follows:

Year
Amount

2005 $ 2,845,000

2006 40,000

2007 1,489,100

2008 30,000

Subtotal 4,404,100

Accrued dividends payable 649,692

Less Accretion cost included above (398,179 )

Shares subject to mandatory redemption $ 4,655,613

The above table presents redemption amounts due on the Company's preferred stock as of December 31, 2004.

The Company has classified $3,260,312 of the Company's liability related to its shares subject to redemption as short-term and includes redemption payments due in 2005 and the related dividends.

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.

Using a credit-adjusted risk fee rate of 12%, an estimated useful life of wells ranging from 30-40 years, and estimated plugging and abandonment cost ranging from $5,000 per well to $10,000 per well, the Company has recorded a non-cash charge related to the cumulative effect of a change in accounting

F-23

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 accumulated depletion on this cost through that date. A corresponding obligation totaling $611,395 was also been recorded as of January 1, 2003.

For the year ended December 31, 2004 and 2003, the Company recorded accretion expenses of $73,368 associated with this liability. These expenses are included in interest expense in the consolidated statements of loss. Had the provisions of this Statement been reflected in the financial statements for the year ended December 31, 2002 asset retirement obligations of $532,269 would have been recorded as of January 1, 2002.

Pro-forma net loss for the years ended December 31, 2002 is as follows:

	2002
Net loss:
As reported	$	(3,661,344	)
Accretion	$	(79,126	)

Pro-forma net loss	$	(3,740,470	)

The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2004:


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

11. Stock Options

In October 2000, the Company approved a Stock Incentive Plan. The Plan is effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to Employees under the plan shall not exceed 1,000,000. Options are not transferable, fully vest after two years of employment with the Company, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Nonqualified Stock Option Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the Fair Market Value of such shares on the date of grant.

F-24

Furthermore, an employee in the Plan may not, immediately prior to the grant of an Incentive Stock Option hereunder, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such an Employee is at least 110% of the Fair Market Value of the Company’s stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.

Stock option activity in 2004, 2003 and 2002 is summarized below:

	2004					2003					2002
				Weighted Average Exercise					Weighted Average Exercise				Weighted Average Exercise
	Shares			Price		Shares			Price		Shares		Price
Outstanding,
beginning of
year		461,590		$	1.32		676,770		$	7.71		516,028	$	9.23
Granted		--			--		436,000			0.50		160,742		2.86
Exercised		(142,000	)		.50		(94,000	)		0.50		--		--
Expired/canceled		(24,437	)		6.89		(557,180	)		8.57		--		--

Outstanding
and exercisable,
end of year		295,153		$	1.26		461,590		$	1.32		676,770	$	7.71

The following table summarizes information about stock options outstanding at December 31, 2004:

		Options Outstanding				Options Exercisable
Weighted Average Exercise				Weighted Average Remaining Contractual
Price		Shares		Life (years)		Shares
$	0.50		200,000		1.33		200,000
$	2.86		95,153		0.58		95,153
Total		295,153				295,153

No options were granted in 2004. The weighted average fair value per share of options granted during 2003 and 2002 is $0.16 and $1.45 respectively, calculated using the Black-Scholes Option-Pricing model.

F-25

No compensation expense related to stock options was recognized in 2004, 2003 or 2002.

For employees, the fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2003 and 2002. Expected volatility of 40% for 2003, 74.2% for 2002; a risk free interest rate of 3.67% in 2003, 3.67% in 2002; and an expected option life of 3 years for 2003 and 2002.

12. Income Taxes

The Company has no taxable income during each of the three year period ended December 31, 2004.

A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of loss is as follows:

December 31,	2004			2003			2002
Statutory rate		34	%		34	%		34	%
Tax benefit at statutory rate	$	(678,000	)	$	(1,082,000	)	$	(1,073,000	)
State income tax benefit		(79,000	)		(126,000	)		(125,000	)
Other		(41,000	)		(65,000	)		(64,000	)
Non-deductible interest		315,000			175,000			--
Increase in deferred tax asset
valuation allowance		483,000			1,098,000			1,262,000

Total income tax provision	$	--		$	--		$	--

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

December 31	2004			2003			2002
Deferred tax assets:
Net operating loss carryforward	$	10,438,000		$	9,779,000		$	8,415,000
Capital loss carry forward		263,000			263,000			263,000

Total deferred tax assets		10,701,000			10,042,000			8,678,000

Deferred tax liability:
Basis difference in pipeline		806,000			630,000			364,000

Total deferred liability		806,000			630,000			364,000

Total net deferred taxes		9,895,000			9,412,000			8,314,000

Valuation allowance		(9,895,000	)		(9,412,000	)		(8,314,000	)

Net deferred liability	$	--		$	--		$	--

F-26

The Company recorded a valuation allowance at December 31, 2004, 2003 and 2002 equal to the excess of deferred tax assets over deferred tax liabilities, as management is unable to determine that these tax benefits are more likely than not to be realized. Potential future reversal of the portion of the valuation allowance relative to deferred tax asset resulting from the exercise of stock options will be recorded as additional paid in capital realized.

As of December 31, 2004, the Company had net operating loss carry-forwards of approximately $25,318,000 which will expire between 2011 and 2023 if not utilized.

13. Supplemental Cash
Flow Information

The Company paid approximately $697,000, $635,000 and $571,000 for interest in 2004, 2003 and 2002, respectively. No interest was capitalized in 2004, 2003 or 2002.No income taxes were paid in 2004, 2003, or 2002.

14. Rights Offering

On October 17, 2003, the Company filed a Registration Statement on Form S-1 with the Securities and Exchange Commission (“SEC”). On February 13, 2004, the SEC deemed the Registration Statement on Form S-1 effective.

Each subscription right, in addition to the right to purchase three shares of common stock, carried with it an over-subscription privilege. The over-subscription privilege provided stockholders that exercise all of their basic subscription privileges with the opportunity to purchase those shares that were not purchased by other stockholders through the exercise of their basic subscription privileges, at the same subscription price per share. In no event could any subscriber purchase shares of the Company’s common stock in the offering that, when aggregated with all of the shares of the Company’s common stock otherwise owned by the subscriber and his, her or its affiliates, would immediately following the closing, represent more than 50% of the Company’s issued and outstanding shares.

As 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

F-27

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 have been used to pay non-bank indebtedness in the aggregate amount of approximately $6 million (including up to $3,850,000 in principal amount plus accrued interest owed by the Company to Dolphin) and to pay $1,157,000 as a portion of 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. On April 29, 2004, a final hearing for approval of the settlement was held. The Court entered its order approving the settlement on May 10, 2004. Class members may file their claims against the settlement fund through July 15, 2004. The fund will be disbursed in accordance with the claims filed. 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 will issue 300,000 warrants to purchase a share of the Company’s common stock for a period of three years from date of issue at $1 per share subject to adjustments. These warrants were not issued as of

F-28

December 31, 2004. All expenses including attorney’s fees are to be paid out of these settlement funds. 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. The interest rate was the Bank One base rate plus one-quarter percent.

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. The Company was paying $200,000 per month toward the outstanding balance of the credit facility until the settlement. 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 entered into an agreement, settling its lawsuit with Bank One.

On May 13, 2004, the Company and Bank One executed a written agreement resolving all claims against each other. Pursuant to that agreement, 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 releases of its liens on all of the Company’s properties securing the credit facility upon receipt of the agreed payment. Bank One retained a right to seek specific performance of the May 13, 2004 agreement if payment were not made by May 18, 2004 and to recover attorney’s fees if such relief were sought. The Company and the Bank each agreed to bear all of its own costs, expenses, and attorneys’ fees incurred to date.

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 bridge loan from Dolphin Offshore Partners, LP (“Dolphin”) (the managing partner of Dolphin is Peter E. Salas, the 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 loan is secured by a first lien on the Company’s Tennessee and Kansas producing properties and the Tennessee pipeline. The balance of the settlement amount of $1,157,000 was paid from

F-29

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. Quarterly Data and Share
Information (unaudited)

The following table sets forth, for the fiscal periods indicated, selected consolidated financial data.

	Fiscal Year Ended 2004
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter(b)
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

Income/loss per common share	$	(0.07)		$	(0.01	)	$	(0.02	)	$	0.00

				Fiscal Year Ended 2003
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter(a)
Revenues	$	1,971,603		$	1,482,390		$	1,599,461		$	1,151,796
Net loss		(282,162	)		(678,592	)		(744,881	)		(1,492,027	)
Cumulative effects of
changes in accounting
principles		(351,204	)		--			365,675			--
Net income (loss)
attributable to common
stockholders		(767,561	)		(812,786	)		(379,206	)		(1,492,027	)

Earnings (loss) per
common share
Operations		(0.02	)		(0.07	)		(0.07	)	$	(0.12	)
Cumulative effects		(0.03	)		--			0.03			--

Total	$	(0.05	)	$	(0.07	)	$	( 0.04)		$	(0.12	)

(a)	During the fourth quarter of 2003, the Company recognized an impairment loss on equipment totaling $495,000.

(b)	A gain on exchange of Preferred Stock was recorded in the amount of $458,310, in the fourth quarter of 2004.

F-30

18. Supplemental Oil
and Gas
Information

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, 2004, 2003 and 2002.

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, 2004, 2003 and 2002:

	2004			2003		2002
Property acquisitions
Proved	$	--		$	--	$	--
Unproved		--			--		--
Less - proceeds from
sales of properties		(77,868	)		--		(100,000	)
Development costs		1,200,771			480,421		2,082,529

	$	1,122,903		$	480,421	$	1,982,529

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the Company’s results of operations from oil and gas producing activities for the years ended:

December 31,	2004			2003			2002
Revenues	$	6,013,374		$	6,040,872		$	5,437,723
Production costs and taxes		(3,241,905	)		(3,412,201	)		(3,094,731	)
Depreciation, depletion and
amortization		(1,285,443	)		(1,268,470	)		(1,388,138	)

Income from oil and gas
producing activities	$	1,486,026		$	1,360,201		$	954,854

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.

F-31

Oil and Gas Reserves (unaudited)

The following table sets forth the Company’s net proved oil and gas reserves at December 31, 2004, 2003 and 2002 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The reserve information indicated below requires substantial judgment on the part of the reserve engineers, resulting in estimates which are not subject to precise determination. Accordingly, it is expected that the estimates of reserves will change as future production and development information becomes available and that revisions in these estimates could be significant. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (MCF) in the case of gas.

Oil (bbls)
Gas (Mcf)

Proved reserves:

Balance, January 1, 2002 1,056,675 25,880,202

Discoveries and extensions 34,968 937,000

Revisions of previous estimates 542,229 786,430

Production (157,973 ) (1,004,899 )

Balance, December 31, 2002 1,475,899 26,598,733

Discoveries and extensions -- --

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 )

Proved reserves at December 31, 2004 1,090,000 7,947,000

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

Proved developed producing

reserves at December 31, 2002 1,108,293 6,592,711

Of the Company’s total proved reserves as of December 31, 2004, 2003 and 2002, approximately 69%, 51% and 37% respectively, were classified as proved developed producing, 17%, 14% and 19% respectively, were classified as proved developed non-

F-32

producing and 14%, 35% and 44% respectively, were classified as proved undeveloped. All of the Company’s reserves are located in the continental United States.

Standardized Measure of Discounted Future Net Cash Flows(unaudited)

The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table:

	(amounts in thousands)
December 31,	2004			2003			2002
Future cash inflows	$	100,516		$	109,102		$	152,180
Future production
costs and taxes		(47,129	)		(48,761	)		(41,870	)
Future development costs		(1,757	)		(5,957	)		(11,348	)
Future income tax expenses		--			--			--

Net future cash flows		51,630			54,384			98,962
Discount at 10% for
timing of cash flows		(24,899	)		(28,021	)		(52,314	)

Discounted future net cash flows from
proved reserves	$	26,731		$	26,363		$	46,648

	(amounts in thousands)
	2004			2003			2002
Balance, beginning of year	$	26,363		$	46,648		$	21,734
Sales, net of production costs
and taxes		(2,772	)		(2,884	)		(2,343	)
Discoveries and extensions		595			--			1,686
Changes in prices and
production costs		11,127			(9,040	)		20,586
Revisions of quantity estimates		(12,574	)		(13,988	)		6,120
Development costs incurred		--			--			--
Interest factor - accretion
of discount		2,636			4,665			2,173
Net change in income taxes		--			--			--
Changes in future development costs		4,201			5,391			(4,860	)
Changes in production rates
and other		(2,845	)		(4,429	)		1,552

Balance, end of year	$	26,731		$	26,363		$	46,648

F-33

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, 2004, 2003 and 2002 were $40.92, $29.72 and $27.25 per barrel of oil and $7.04, $4.76 and $4.01 per MCF of gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions. The estimates of reserve values include estimated future development costs that the Company does not currently have the ability to fund. If the Company is unable to obtain additional funds, it may not be able to develop its oil and natural gas properties as estimated in its December 31, 2004 reserve report.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable net operating loss carry-forwards, for both regular and alternative minimum tax. For the years ended December 31, 2004, 2003 and 2002 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.

19. Subsequent Events

On March 4, 2005 the Company sold the Kansas gas wells, oil and gas 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 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.L.P. to reduce the principal of the promissory note in amount of $2.5 million to $150,000.

F-34

December 31,	2004			2003
Liabilities and Stockholders’ Equity (Note 1)
Current liabilities
Current maturities of long-term debt (Note 7)	$	26,672		$	6,127,290
Accounts payable		319,820			1,075,948
Accrued interest payable		25,367			234,321
Other accrued liabilities		211,622			18,560
Notes payable to related parties (Note 3)		3,050,000			3,709,000
Drilling program (Note 9)		1,316,702			--
Current shares subject to mandatory redemption (Note 9)		3,260,312			1,261,876

Total current liabilities		8,210,495			12,426,995
Shares subject to mandatory redemption (Note 9)		1,395,301			6,035,183
Drilling program (Note 9)		438,901			--
Asset retirement obligations (Note 10)		708,677			668,556
Long term debt, less current maturities (Note 7)		106,688			221,635

Total liabilities		10,860,062			19,352,369

Commitments and Contingencies (Notes 5, 7, 8, and 10)
Stockholders' equity (Note 11)
Common stock, $.001 par value; authorized 100,000,000 shares;
48,756,977 and 12,064,977 shares issued and outstanding		48,757			12,080
Additional paid-in capital		51,686,454			42,721,290
Accumulated deficit		(33,385,524	)		(31,391,499	)
Accumulated other comprehensive loss		--			(90,000	)

Total stockholders' equity		18,349,687			11,251,871

	$	29,209,749		$	30,604,240


Net cash provided by (used in) financing activities		1,202,060			(122,422	)		3,246,633


Net change in cash and cash equivalents		(44,931	)		128,536			(209,321	)

Cash and cash equivalents, beginning of year		312,666			184,130			393,451


Cash and cash equivalents, end of year	$	267,735		$	312,666		$	184,130

Supplemental disclosure of non-cash investing and
financing activities:
Issuance of common stock on conversion of debt		--		$	69,549		$	120,000
Issuance of common stock and stock options for
services received and charitable contributions made		--		$	203,812		$	48,620
Purchase of equipment by issuing common stock		--				-	$	150,000
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		$	--			--

December 31,	2004		2003
Unsecured note payable to a Director due
January 2004, with interest payable
quarterly at 8% per annum. Note is
convertible into common stock of the
Company at a rate of $2.88 per share of
common stock	$		$ 500,000

Notes payable to a Director due with
interest payable quarterly at 12% per annum. Notes are secured by the pipeline
		-	3,209,000

Notes payable to a Director due May 2005
with interest payable monthly at 12% per
annum. Notes are secured by Tennessee and
Kansas producing properties and the
pipeline	3,050,000		--

Total short term debt to related
parties	$3,050,000		$3,709,000

Year	Amount
2005	$	2,845,000
2006		40,000
2007		1,489,100
2008		30,000

Subtotal		4,404,100

Accrued dividends payable		649,692
Less Accretion cost included above		(398,179	)

Shares subject to mandatory redemption	$	4,655,613


Proved reserves:
Balance, January 1, 2002	1,056,675		25,880,202
Discoveries and extensions	34,968		937,000
Revisions of previous estimates	542,229		786,430
Production	(157,973	)	(1,004,899	)

Balance, December 31, 2002	1,475,899		26,598,733
Discoveries and extensions	--		--
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	)

Proved reserves at December 31, 2004	1,090,000		7,947,000


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


Proved developed producing
reserves at December 31, 2002	1,108,293		6,592,711

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

REPORT ON FORM 10-K

FORWARD LOOKING STATEMENTS

PART I

History of the Company

Overview

General

1. The Swan Creek Field

A. Swan Creek Pipeline Facilities

B. Swan Creek Production and Development

2. The Kansas Properties

3. Other Areas of Development

Governmental Regulations

Principal Products or Services and Markets

Drilling Equipment

Distribution Methods of Products or Services

Competitive Business Conditions, Competitive Position in the Industryand Methods of Competition

Sources and Availability of Raw Materials

Dependence On One or a Few Major Customers

Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts, Including Duration

Need For Governmental Approval of Principal Products or Services

Effect of Existing or Probable Governmental Regulations On Business

Research and Development

Number of Total Employees and Number of Full-Time Employees

Risk Factors

The Company’s Auditors Have Issued Their Audit Report, Which Includes An Explanatory Paragraph Emphasizing Substantial Doubt About the Company’s Ability To Continue As A Going Concern For One Year From The Balance Sheet Date (December 31, 2004).

Declines In Oil and Gas Prices WillMaterially Adversely Affect the Company.

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

Oil and Gas Operations Involve Substantial Costsand Are Subject To Various Economic Risks.

The Company Has Significant Costs To Conform ToGovernment Regulation Of The Oil and Gas Industry.

The Company Has Significant Costs Related To Environmental Matters.

Insurance Does Not Cover All Risks.

The Company Is Not Competitive WithRespect To Acquisitions Or Personnel.

The Company Depends On Key Personnel,Whom It May Not Be Able To Retain Or Recruit.

General Economic Conditions.

Available Information

ITEM 2. PROPERTIES

Property Location, Facilities, Size and Nature of Ownership

Swan Creek Field

Kansas Properties

Reserve Analyses

Production

Oil and Gas Drilling Activities

Gross and Net Wells

Productive Wells

Developed and Undeveloped Oil and Gas Acreage

ITEM 3. — LEGAL PROCEEDINGS

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

PART II

Market Information

Holders

Dividends

Recent Sales of Unregistered Securities

Purchases of Equity Securities by the Companyand Affiliated Purchasers

The Rights Offering

ITEM 6. SELECTED FINANCIAL DATA

As of December 314 5 6 ,

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

Results of Operations

Liquidity and Capital Resources

Critical Accounting Policies

Revenue Recognition

Full Cost Method of Accounting

Oil and Gas Reserves/Depletion Depreciationand Amortization of Oil and Gas Properties

Asset Retirement Obligations

CONTRACTUAL OBLIGATIONS

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Commodity Risk

Interest Rate Risk

Forward-Looking Statements And Risk

ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9A CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Changes in Internal Controls

ITEM 9B OTHER INFORMATION

PART III

ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Identification of Directors and Executive Officers

Business Experience

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

Competitive Business Conditions, Competitive Position in the Industry
and Methods of Competition

Patents, Trademarks, Licenses, Franchises, Concessions,
Royalty Agreements or Labor Contracts, Including Duration

The Company’s Auditors Have Issued Their Audit Report,
Which Includes An Explanatory Paragraph Emphasizing
Substantial Doubt About the Company’s Ability To Continue
As A Going Concern For One Year From The Balance
Sheet Date (December 31, 2004).

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

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

Oil and Gas Operations Involve Substantial Costs
and Are Subject To Various Economic Risks.

The Company Has Significant Costs To Conform To
Government Regulation Of The Oil and Gas Industry.

The Company Is Not Competitive With
Respect To Acquisitions Or Personnel.

The Company Depends On Key Personnel,
Whom It May Not Be Able To Retain Or Recruit.

Purchases of Equity Securities by the Company
and Affiliated Purchasers

As of December 31^{4 5 6} ,

Oil and Gas Reserves/Depletion Depreciation
and Amortization of Oil and Gas Properties

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

Aggregate Option Exercises For Fiscal 2004
and Year End Option Values

Compensation Committee Interlocking
And Insider Participation

Five Percent Stockholders¹⁴

Directors and Officers¹⁷

Tengasco, Inc.and
Subsidiaries

Consolidated Financial StatementsYears
Ended December 31, 2004, 2003 and 2002

2. Summary of
Significant
Accounting Policies

3.Related Party
Transactions

4.Oil and Gas
Properties