**UNITEDSTATES**

**SECURITIESANDEXCHANGECOMMISSION**

**WASHINGTON,D.C. 20549**

 

**REPORTONFORM            10-K**

(Mark            one)

xAnnual Report pursuant to Section 13 or            15(d) of the Securities Exchange Act of 1934 for the fiscal year ended**December 31, 2007**or

 

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

 

Commission File No.            1**-**15555

 

**TENGASCO,INC.**

(Name            of registrant as specified in its charter)

 

|   | **Tennessee** | **87-0267438** |
|--------|---------------|----------------|

|   | (State or other jurisdiction of | (I.R.S. Employer |
|--------|---------------------------------|------------------|

|   | incorporation or organization) | Identification No.) |
|--------|--------------------------------|---------------------|

 

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

|   | (Address of Principal Executive Offices) | (Zip Code) |
|--------|------------------------------------------|------------|

 

|   | Registrant's telephone number, including area                            code:

**(865) 675-1554**. |
|--------|-----------------------------------------------------------------------------------------------------|

 

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

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

 

Indicate by check mark if the registrant is a well-known seasoned            issuer, as defined by Rule 405 of the Securities Act. Yes            o Nox

 

Indicate by check mark if the registrant is not required to file reports            pursuant to Section 13 or Section 15(d) of the Act. Yes o            Nox

 

Indicate by check mark whether the registrant (1) filed all reports            required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934            during the preceding 12 months (or for such shorter period that the registrant was            required to file such reports), and (2) has been subject to such filing requirements            for the past 90 days. YesxNo            o

 

Indicate by check mark if disclosure of delinquent filers in response to            Item 405 of Regulation SK is not contained herein, and will not be contained, to the            best of registrant's knowledge, in definitive proxy or information statements            incorporated by reference in Part III of this Form 10-K or any amendment to this Form            10-K. []

 

Indicate by check mark whether the registrant is a large accelerated            filer, an accelerated filer, a non-accelerated filer or smaller reporting company. See            definitions of “large accelerated filer,” “accelerated filer”            and “smaller reporting company” in Rule 12b-2 of the Exchange            Act.

 

| Large Accelerated Filer                            o | Accelerated Filer                            o | Non-accelerated Filer                            o | Smaller Reporting Companyx |
|------------------------------------------------------|------------------------------------------------|----------------------------------------------------|----------------------------|

|   | (Do not check if a Smaller |
|--------|----------------------------|

|   | Reporting Company) |
|--------|--------------------|

Indicate by checkmark whether the registrant is a shell company (as            defined in Rule 12b-2 of the Exchange Act). Yes o            Nox

 

State the aggregate market value of the voting and non-voting common            equity held by non-affiliates computed by reference to the price at which the common            equity was last sold, or the average bid and asked price of such common equity, as of            the last business day of the registrant’s most recently completed second fiscal            quarter (June 29, 2007 closing price $0.65):**$24,375,566**

 

State the number of shares outstanding of the registrant's $.001 par            value common stock as of the close of business on the latest practicable date (March 3,            2008):**59,155,750**

 

**Documents Incorporated By Reference**

 

The information required by Part III of the Form 10-K, to the extent not            set forth herein, is incorporated herein by reference from the registrant's definitive            proxy statement for the Annual Meeting of Shareholders to be held on June 2, 2008, to            be filed with the Securities and Exchange Commission pursuant to Regulation 14A not            later than 120 days after the close of the registrant's fiscal year.

 

 

 

 

 

 

| **Part I**   | **Table of Contents**                                                                                                                                                                  | Page                                           |
|--------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------|
|         | Item 1.    Business                                                                                                                                                | 1                                              |
|         | Item 1A.  Risk Factors                                                                                                                                                       | 18                                             |
|         | Item 1B. Unresolved Staff Comments                                                                                                                                                     | 27                                             |
|         | Item 2. Properties                                                                                                                                                                     | 27                                             |
|         | Item 3. Legal Proceedings                                                                                                                                                              | 38                                             |
|         | Item 4. Submission of Matters to a Vote of Security                            Holders                                                                                                 |  

38                                     |
| **Part II**  |                                                                                                                                                                                   |                                           |
|         | Item 5.  Market for Registrant’s Common                            Equity, Related Stockholder Matters and Issuer Purchases of Equity                            Securities |  

                             

38 |
|         | Item 6.       Selected                            Financial Data                                                                                         | 40                                             |
|         | Item 7. Management’s Discussion and Analysis of                            Financial Condition and Results of Operation                                                          |  

41                                     |
|         | Item 7A.    Quantitative and                            Qualitative Disclosures About Market Risk                                                                  |  

49                                     |
|         | Item                            8.       Financial Statements and                            Supplementary Data                                     |  

50                                     |
|         | Item 9. Changes in and Disagreements With                            Accountants on Accounting and Financial Disclosure                                                           |  

50                                     |
|         | Item 9A(T) Controls and Procedures                                                                                                                                                | 50                                             |
|         | Item 9B.    Other Information                                                                                                                                           | 52                                             |
| **Part III** |                                                                                                                                                                                   |                                           |
|         | Item 10.    Directors and Executive                            Officers and Corporate Governance                                                                        |  

53                                     |
|         | Item 11.    Executive                            Compensation                                                                                                           | 53                                             |
|         | Item 12.    Security Ownership of Certain                            Beneficial Owners and Management and Related Stockholder                            Matters        |  

                             

53 |
|         | Item 13.   Certain Relationships and Related                            Transactions, and Director Independence                                                              |  

55                                     |
|         | Item 14.   Principal Accountant Fees and                            Services                                                                                            | 55                                             |
| **Part IV**  |                                                                                                                                                                                   |                                           |
|         | Item 15.  Exhibits, Financial Statement and                            Schedules                                                                                             | 55                                             |
|         | **SIGNATURES**                                                                                                                                                                         | 58                                             |
|         |                                                                                                                                                                                   |                                           |

**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 2007 and            thereafter; oil and gas prices; exploration activities; development expenditures; costs            of regulatory compliance; environmental matters; technological developments; future            products or product development; the Company’s products and distribution            development strategies; potential acquisitions or strategic alliances; liquidity and            anticipated cash needs and availability; prospects for success of capital raising            activities; prospects or the market for or price of the Company’s common stock;            and control of the Company. All forward-looking statements are based on information            available to the Company as of the date hereof, and the Company assumes no obligation            to update any such forward-looking statements. The Company’s actual results could            differ materially from the forward-looking statements. Among the factors that could            cause results to differ materially are the factors discussed in “Risk            Factors” below in Item 1A of this Report.

 

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

 

**PART            I**

 

| **ITEM 1.** | **BUSINESS**. |
|-------------|---------------|

 

**History of the Company**

 

The            Company was initially organized in Utah in 1916 for the purpose of mining, reducing and            smelting mineral ores, under the name Gold Deposit Mining & Milling Company and            later changed to Onasco Companies, Inc. In 1995, the Company changed its name from            Onasco Companies, Inc. by merging into Tengasco, Inc., a Tennessee corporation, formed            by the Company solely for this purpose.

 

**Overview**

 

The            Company is in the business of exploring for, producing and transporting oil and natural            gas in Kansas and Tennessee. The Company leases producing and non-producing

 

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properties with a view toward exploration and development and owns            pipeline and other infrastructure facilities used to provide transportation services.            The Company utilizes seismic technology to improve the discovery of            reserves.

 

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 Company sold the Kansas gas producing wells, gathering system and            compressors effective February 1, 2005. During 2007, the Kansas Properties produced an            average of 14,860 barrels of oil per month.

 

The            Company’s oil and gas leases in Tennessee are located in Hancock, Claiborne, and            Jackson counties. The Company has drilled primarily on a portion of its leases known as            the Swan Creek Field in Hancock County focused within what is known as the Knox            Formation, one of the geologic formations in that field. During 2007 the Company sold            an average of 347 thousand cubic feet of natural gas per day and 573 barrels of oil per            month from 21 producing gas wells and 5 producing oil wells in the Swan Creek            Field.

 

The            Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation            (“TPC”), owns and operates a 65-mile intrastate pipeline which it            constructed to transport natural gas from the Company’s Swan Creek Field to            customers in Kingsport, Tennessee.

 

The            Company formed a wholly-owned subsidiary on December 27, 2006 named Manufactured            Methane Corporation for the purpose of owning and operating treatment and delivery            facilities using the latest developments in available technologies for the extraction            of methane gas from non-conventional sources for delivery through the nation’s            existing natural gas pipeline system, including the Company’s TPC pipeline system            in Tennessee for eventual sale to natural gas customers.

 

In            December 2007 the Company entered into a management agreement with Hoactzin Partners,            L.P. (“Hoactzin”) to manage Hoactzin’s oil and gas properties in the            Gulf of Mexico offshore Texas and Louisiana. As consideration for that agreement the            Company obtained reimbursement from Hoactzin of a portion of salary and expenses for            the Company’s Vice President Patrick McInturff, as well as an option to            participate in production and exploration activities in Hoactzin’s properties and            has begun investigating the economics of participation in oil and gas projects in those            areas. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the            controlling person of Hoactzin. He is also the sole shareholder and controlling person            of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P.,            which is the Company’s largest shareholder.

             

**General**

 

| **1.****The                            Kansas Properties** |   |
|------------------------------------------------------------|--------|

 

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The            Company’s Kansas Properties presently include 149 producing oil wells in the            vicinity of Hays, Kansas. The Company employs a full time geologist in Kansas to            oversee acquisition of new properties, and exploration and exploitation of Kansas            Drilling prospects on both newly acquired acreage and existing leases for development.            The Company employs a full time production manager to oversee the daily function of all            producing wells and to implement the work-over programs employed by the Company to            boost production from older wells.

 

In            2007, the Company continued to focus its exploration and drilling activities in Kansas.            In 2007, the Company drilled 16 new wells on its Kansas Properties, of which 9 wells            were under the ten well program discussed below in greater detail. Of these new wells,            10 are producing commercial quantities of oil. These new wells are producing            approximately 135 barrels of oil per day. The Company also continued in 2007 its            program of work-overs of existing wells to increase production. The Company’s            focus in 2007 on its Kansas oil production and the results achieved by the Company from            its ongoing operations, drilling and work-overs are having a positive impact on the            Company’s reserves resulting in the Company’s total proved reserves at            December 31, 2007 having more than doubled in value from year-end 2006. Fifty-Six (56%)            percent of that increase in reserve growth is attributable to the Company’s            ongoing operational activities and the new Proved Undeveloped (PUD) future drilling            locations that the Company has established as a result of these successes. See, Item 2,            “Properties” – “Reserve Analysis” for a more detailed            discussion of the Company’s reserves.

 

During 2007, the Company also continued its lease acquisition program in            Kansas to acquire oil and gas leases in areas near its previous lease holdings where            the Company believes there is a likelihood of additional oil production. The Company            continued to collect and analyze substantial seismic data to aid it in its drilling            operations. The Company intends in 2008 to continue to acquire additional leases in the            area of its existing wells.      

 

|   | **A.** | **Kansas Drilling Programs** |
|--------|--------|------------------------------|

 

*1. The Ten Well Program*

             

On September 17, 2007, the Company entered into a drilling program with            Hoactzin for ten wells consisting of approximately three wildcat wells and seven            developmental wells to be drilled on the Company’s Kansas Properties (the            “Program”). Under the terms of the Program, Hoactzin was to pay the Company            $400,000 for each well in the Program completed as a producing well and $250,000 per            drilled well that was non-productive. The terms of Program also provide that Hoactzin            will receive all the working interest in the ten wells in the Program, but will pay an            initial fee to the Company of 25% of its working interest revenues net of operating            expenses. This is referred to as a management fee but as defined is in the nature of a            net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of            working interest revenues when net revenues received by Hoactzin reach an agreed payout            point of

 

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approximately 1.35 times Hoactzin’s purchase price (the            “Payout Point”). The Company intends to account for funds received for            interests in the Program as an offset to oil and gas properties.

 

As            of the date of this Report, the Company has drilled all ten wells in the Program. Of            the ten wells drilled, nine were completed as oil producers and are currently producing            approximately 106 barrels per day in total. Hoactzin paid a total of $3,850,000 for its            interest in the Program resulting in the Payout Point being determined as $5,215,595.            The amount paid by Hoactzin for its interest in the Program wells exceeded the            Company’s actual drilling costs of approximately $2.8 million for the ten wells            by more than $1 million.

 

Although production level of the Program wells will decline with time in            accordance with expected decline curves for these types of well, based on the drilling            results of the Program wells and the current price of oil, the Program wells are            expected to reach the Payout Point in approximately four years solely from the oil            revenues from the wells. However, under the terms of its agreement with Hoactzin            reaching the Payout Point could be accelerated by the application of 75% of the net            proceeds Hoactzin receives from the methane extraction project being developed by the            Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the            Carter Valley, Tennessee landfill toward reaching the Payout Point. (The methane            extraction project is discussed in greater detail below.) Those methane project            proceeds when applied will result in the Payout Point being achieved sooner than the            estimated four year period based solely upon revenues from the Program            wells.

 

|   | *2. The Eight Well Program* |
|--------|-----------------------------|

 

|   | *3. The Twelve Well Program* |
|--------|------------------------------|

 

 

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In October, 2005 the Company accepted an exchange from Hoactzin of            promissory notes made by the Company in the principal amount of $2,514,000 for a 94.3%            working interest in a twelve well drilling program (the “Twelve Well            Program”) by the Company on its Kansas Properties. The Company retained the            remaining 5.7% working interest in the Twelve Well Program. The promissory notes            exchanged were originally issued by the Company in connection with loans made to the            Company by Dolphin Offshore Partners, L.P. to fund the Company’s cash exchange to            holders of its Series A, B and C Preferred Stock.

In            2006, the Company drilled four wells in the Twelve Well Program bringing the total            number of wells drilled in that Program to six. All but one of those wells is            continuing to produce commercial quantities of oil.

 

On            June 29th, 2006 the Company closed a $50,000,000 credit facility with Citibank Texas,            N.A. The Company’s initial borrowing base was set at $2,600,000 and the Company            borrowed that amount on June 29, 2006 and used $1.393 million of the loan proceeds to            exercise its option to repurchase from Hoactzin, the Company’s obligation to            drill the final six wells in the Company’s Twelve Well Program. As a result of            the repurchase, the Twelve Well Program was converted to a six well program, all of            which had been drilled by the Company at the time of the repurchase. Consequently, all            well-drilling obligations of the Company under both the Eight Well and Twelve Well            Programs with former preferred stockholders as participants have been satisfied. If the            Company had not exercised its repurchase option, Hoactzin would have received a 94%            working interest in the final six wells of the Twelve Well Program. However, as a            result of the repurchase, Hoactzin will now receive only a 6.25% overriding royalty in            six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six            program wells that had previously been drilled as part of the Twelve Well Program.            These overriding royalties were part of the terms agreed upon at the inception of the            Twelve Well Program if the repurchase option was exercised.

             

|   | **B.** | **Kansas Production** |
|--------|--------|-----------------------|

 

Gross oil production in 2007 was just slightly less than 2006 resulting            from the loss of production in January 2007 due to an electricity outage caused by an            ice storm. As a result of that storm, many counties in Kansas, including some counties            where the Company has wells, lost power for the entire month of January.             Producing wells in those counties were unable to produce without electricity to run the            well pumps during the power outage.  Consequently, in January 2007 the Company saw            production and revenue decline from monthly levels in late 2006.  None of the            Company’s producing wells were physically damaged by the ice storm or by            non-production during the absence of power, but the storm did substantially adversely            impact production levels and sales in the first two months of 2007 while at the            same time causing an increase in expenses.  Eventually new poles and lines were            rebuilt on a locally massive scale and electrical power was restored, and the Company            experienced a rebound of production commencing in March 2007. In 2007, the Company            produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006, a decrease of            1,244 barrels for the year. Additionally, the wells in the Eight Well Program reached            the reversionary “flip point” in April 2007. This is the point            at

 

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which the Company started receiving 85% of the participant’s            interest plus the Company’s original interest of (19.6%) for an approximate total            net interest to the Company equal to an 88% working interest. In 2007, the wells from            the Eight Well Program produced 22,195 gross barrels of oil; the wells in the Twelve            Well Program (now converted to a six well program) produced 15,864 gross barrels; wells            that were polymered produced 19,502 barrels; and the two new wells drilled produced            2,566 gross barrels in 2007. The Ten Well Program had some limited production in 2007            as wells were being completed through the year-end. During 2007, the Ten Well Program            produced 3,649 barrels from 5 wells that were completed by year-end. The five other            wells in the Ten Well Program that were drilled in 2007 were completed in 2008. In            March 2008 the tenth and final well from the Ten Well Program was drilled and completed            as a producer. As of the date of this Report, nine of ten wells drilled in the Program            have been completed as producers and are producing approximately 106 barrels per day.            During the first half of 2008 the Company expects the reversionary flip point for the            Twelve Well Program now converted to a six well program, to be achieved.

 

There are also additional capital development projects that the Company            is considering to increase current oil production with respect to the Kansas            Properties, including recompletion of wells and major work-overs. Management has made            the decision to simultaneously undertake as many of these projects that can be paid            from the Company’s current cash flow as soon as the Company is able to obtain            third party crews and equipment to perform the work. Workovers done to date on a            limited scale have been successful in Kansas. The work-overs 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 combined oil/water 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 work-overs when completed might reduce water production and its            associated removal expense and increase oil production from several of the            Company’s other existing oil wells in Kansas.

 

| **2.****The                            Tennessee Properties** |   |
|---------------------------------------------------------------|--------|

 

Amoco Production Company, during the late 1970’s and early            1980’s acquired approximately 50,500 acres of oil and gas leases in the Eastern            Overthrust in the Appalachian Basin, including the area now referred to as the Swan            Creek Field. In 1982, Amoco successfully drilled two natural gas discovery wells in the            Swan Creek Field to the Knox Formation. These wells, once completed, had a high            pressure and apparent volume of deliverability of natural gas. In the mid-1980’s,            however, development of this Field was cost prohibitive due to a substantial decline in            worldwide oil and gas prices which was further exacerbated by the high cost of            constructing a necessary 23-mile pipeline across three 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 July 1995, the            Company concluded a legal action under state law and acquired the Swan Creek            leases.

 

| **A.****Swan Creek Pipeline                            Facilities** |   |
|---------------------------------------------------------------------|--------|

 

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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 in 1998. The cost of constructing Phase I of the            pipeline was approximately $4,200,000. Construction of Phase II of the Company’s            pipeline system was completed in 2001. Phase II was an additional 35 miles of eight and            12-inch pipe laid at a cost of approximately $12.1 million, extending the            Company’s pipeline from a point near the terminus of Phase I and connecting to a            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 $16,329,552.

 

| **B.****Swan Creek Production and                            Development** |   |
|----------------------------------------------------------------------------|--------|

 

Management obtained state regulatory approval in 2003 for drilling            additional infield wells in the Swan Creek Field resulting in an increased density of            wells. At that time, management expected that an increased density of wells within the            existing Swan Creek Field would result in additional reserves in accordance with            reservoir engineering standards.

 

Thereafter, the Company drilled and tested two new infield development            wells in the Swan Creek Field. The results of these wells together with the            accumulation of data from previously drilled wells and seismic data indicated that            drilling new gas wells in the Swan Creek Field would not achieve any significant            increase in daily gas production totals from the Field; the current wells in production            in the Swan Creek Field would be capable of and would likely produce all the remaining            reserves in that Field; and, that only limited additional gas reserves could be added            with additional infield developmental drilling. Consequently, the Company has not            drilled any new wells in the Swan Creek Field since 2004.

 

Because no drilling for natural gas directly in Swan Creek is            anticipated in the future, the current production levels less decline are the sole            value of natural gas reserves and production. The existing production and the current            21wells producing natural gas are showing typical Appalachian production declines,            which exhibit a long-lived nature but more modest volumes. The experienced decline in            actual production levels from existing wells in the Swan Creek Field from 2006 to 2007            was expected and predictable. Although there can be no assurance, the Company expects            these natural rates of decline in the future will be comparable to the decline            experienced over the 2006-2007 period, and that ongoing production from existing wells            will tend to stabilize near current production levels. Variations in year-end natural            gas prices and lack of interest to invest in Swan Creek in the foreseeable future have            resulted in an adjustment to the reserve volumes to reflect only the reserves            associated with currently producing wells. The company maintains an interest and            anticipates drilling additional oil prospects in Swan Creek. It also has an interest in            seeking other exploration targets in Tennessee outside of Swan Creek but near the            Company’s pipeline, with other industry partners.

 

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The deliverability of natural gas from the Swan Creek 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. In 2007, the Company’s volume sold from the field was approximately 347            MMBtu per day. The Company’s contracts with these customers are only for natural            gas produced from the Swan Creek Field. So long as that field is not capable of            supplying these volumes of natural gas, 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.

 

During 2007, the Company had 21 producing gas wells and 5 producing oil            wells in the Swan Creek Field. Sales from the Swan Creek Field during 2007 averaged 347            Mcf per day compared to 378 Mcf per day in 2006.

 

| **3.****The                            Methane Project** |  |
|----------------------------------------------------------|--|

 

On            October 24, 2006 the Company signed a twenty-year Landfill Gas Sale and Purchase            Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC            (“BFI”), an affiliate of Allied Waste Industries. The Agreement was            thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured            Methane Corporation (“MMC”) and provides that MMC will purchase all the            naturally produced gas stream presently being collected and flared at the municipal            solid waste landfill in Carter Valley serving the metropolitan area of Kingsport,            Tennessee that is owned and operated by BFI in Church Hill, Tennessee. BFI’s            facility is located about two miles from the Company’s existing pipeline serving            Eastman Chemical Company (“Eastman”). Contingent upon obtaining suitable            financing, the Company plans to acquire and install a proprietary combination of            advanced gas treatment technology to extract the methane component of the purchased gas            stream.  Methane is the principal component of natural gas and makes up about half            of the purchased gas stream by volume. The Company plans to construct a small diameter            pipeline to deliver the extracted methane gas to the Company’s existing pipeline            for delivery to Eastman (the “Methane Project”).

 

MMC            has placed equipment orders for its first stage of process equipment (cleanup and            carbon dioxide removal) and the second stage of process equipment (nitrogen rejection)            for the Methane Project. It is anticipated that the total costs for the Project            including pipeline construction, will be approximately $4.1 million including costs for            compression and interstage controls. The costs of the Methane Project to date have been            funded primarily by (a)

 

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the            money received by the Company from Hoactzin to purchase its interest in the Ten Well            Program which exceeded the Company’s actual costs of drilling the wells in that            Program by more than $1 million (b) cash flow from the Company’s operations in            the amount of approximately $1 million and (c) $825,000 of the funds the Company            borrowed from its credit facility with Sovereign Bank. The Company anticipates that            most of the remaining balance of the Methane Project costs will be paid from the            Company’s cash flow.

 

The            Company anticipates that the equipment ordered by MMC will be manufactured and            delivered to allow operations to begin in mid-2008 after equipment installation,            testing, and startup procedures are begun. Commercial deliveries of gas will begin when            the equipment is installed and tested, the pipeline is constructed and emission permits            are obtained. Upon commencement of operations, the methane gas produced by the project            facilities will be mixed in the Company’s pipeline and delivered and sold to            Eastman Chemical Company (“Eastman”) under the terms of the Company’s            existing natural gas purchase and sale agreement. At current gas production rates and            expected extraction efficiencies, when commercial operations of the Project begin, the            Company would expect to deliver about 418 MMBtu per day of additional gas to Eastman,            which would substantially increase the current volumes of natural gas being delivered            to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas            of $7 per MMBtu, near the average natural gas price received by the Company in 2007,            the anticipated net revenues would be approximately $800,000 per year from the Methane            Project based on anticipated volumes and expenses. The gas supply from this project is            projected to grow over the years as the underlying operating landfill continues to            expand and generate additional naturally produced gas, and for several years following            the closing of the landfill, currently estimated by BFI to occur between the years 2022            and 2026.

 

As part            of the Methane Project agreement, the Company agreed to install a new force-main water            drainage line for BFI, the landfill owner, in the same two-mile pipeline trench as the            gas pipeline needed for the project, reducing overall costs and avoiding environmental            effects to private landowners resulting from multiple installations of pipeline. BFI            will pay the additional costs for including the water line. Construction of the gas            pipeline needed to connect the facility with the Company’s existing natural gas            pipeline began in January 2008. As a certificated utility, the Company’s pipeline            subsidiary, TPC, requires no additional permits for the gas pipeline construction. The            Company currently anticipates that pipeline construction will be concluded            approximately the same time as equipment deliveries and installations occur or in the            May to June 2008 time period, subject to weather delays during wintertime            construction.

 

On            September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten            Well Program, pursuant to a separate agreement with the Company was conveyed a 75% net            profits interest in the Methane Project. When the Methane Project comes online, the            revenues from the Project received by Hoactzin will be applied towards the            determination of the Payout Point (as defined above) for the Ten Well Program. When the            Payout Point is reached from either the revenues from the wells drilled in the Program            or the Methane Project or a combination thereof, Hoactzin’s net profits interest            in the Methane Project will decrease to a 7.5% net profits interest. The Company            believes that the application of revenues from the

 

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methane project to reach the Payout Point couldaccelerate reaching the            Payout Point. As stated above, the price paid by Hoactzin for its interest in the            Program exceeded the Company’s anticipated and actual costs of drilling the ten            wells in the Program. Those excess funds provided by Hoactzin were used to pay for            approximately $1,000,000 of equipment required for the Methane Project, or about 25% of            the Project’s capital costs. The availability of the funds provided by Hoactzin            eliminated the need for the Company to borrow those funds, to have to pay interest to            any lending institution making such loans or to dedicate Company revenues or revenues            from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5%            interest in the Methane Project to Hoactzin was negotiated by the Company as a            favorable element to the Company of the overall transaction.

 

 

| **4.**

****Management                            Agreement with Hoactzin****

                              |   |   |
|-------------------------------------------------------------------------------------------------------------------|--------|--------|

 

**5.****Other Areas of            Development**

 

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

 

10

 

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

The Company 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 or gas produced from non-conventional            sources 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 continue to explore other opportunities such as its Methane            Project in Church Hill, Tennessee to obtain natural gas or substitutes for natural gas            from non-conventional sources if such gas can be economically treated and tendered in            commercial volumes for transportation not only through the Company’s existing            pipeline system but by other delivery mechanisms and through other interstate or            intrastate pipelines or local distribution companies for the purposes of supplementing            the Company’s revenues from the sale of the methane gas produced by these            projects.

 

**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,

 

11

 

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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            cannot 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 or other pipelines that may be connected to the Company’s pipeline            in the future. The Company could, although there can be no assurance, sell its products            to certain local towns, industries and utility districts.

 

At            present, crude oil produced by the Company in Kansas is sold to the Coffeyville            Resources Refining and Marketing, LLC (“Coffeyville Refining”) in Kansas            City, Kansas. Coffeyville Refining is solely responsible for transportation of the oil            it purchases. The Company may sell some or all of its production to one or more            additional refineries in order to maximize revenues as purchase prices offered by the            refineries fluctuate from time to time. Crude oil produced by the Company in Tennessee            is sold to the Ashland refinery in Kentucky and is transported to the refinery by            contracted truck delivery at the Company’s expense.

 

**Drilling Equipment**

 

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

 

**Distribution Methods of Products or Services**

 

Crude oil is normally delivered to refineries in Tennessee and Kansas by            tank truck and natural gas is distributed and transported via pipeline.

 

**Competitive Business Conditions, Competitive Position in the            Industry**

**and Methods of Competition**

 

The            Company's contemplated oil and gas exploration activities in the States of Tennessee            and Kansas will be undertaken in a highly competitive and speculative business            atmosphere. In seeking any other suitable oil and gas properties for acquisition, the            Company will be competing with a number of other companies, including large oil and gas            companies and other independent operators with greater financial resources. Management            does not believe that the Company’s competitive position in the oil and gas            industry will be significant as the Company currently exists.

 

The            Company has numerous competitors in the State of Tennessee that are in the business of            exploring for and producing oil and natural gas in the Kentucky and East Tennessee            areas. Some of these companies are larger than the Company and have greater financial            resources. These companies are in competition with the Company for lease positions in            the known producing areas in which the Company currently operates, as well as other            potential areas of interest.

 

12

 

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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 other industrial customers in the            Kingsport area with which the Company may enter into gas sales contracts.

 

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

 

**Patents, Trademarks, Licenses, Franchises,            Concessions,**

**Royalty Agreements or Labor Contracts, Including            Duration**

 

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

 

**Need For Governmental Approval of Principal Products or            Services**

 

13

 

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

 

The            City of Kingsport, Tennessee has enacted an ordinance granting to TPC a franchise for            twenty years to construct, maintain and operate a gas system to import, transport, and            sell natural gas to the City of Kingsport and its inhabitants, institutions and            businesses for domestic, commercial, industrial and institutional uses. This ordinance            and the franchise agreement it authorizes also require approval of the Tennessee            Regulatory Authority under state law. The Company will not initiate the required            approval process for the ordinance and franchise agreement until such time that it can            supply gas to the City of Kingsport. Although the Company anticipates that regulatory            approval would be granted, there can be no assurances that it would be granted, or that            such approval would be granted in a timely manner, or that such approval would not be            limited in some manner by the Tennessee Regulatory Authority.

 

**Effect of Existing or Probable Governmental Regulations On            Business**

 

Exploration and production activities relating to oil and gas leases are            subject to numerous environmental laws, rules and regulations. The Federal Clean Water            Act requires the Company to construct a fresh water containment barrier between the            surface of each drilling site and the underlying water table. This involves the            insertion of a seven-inch diameter steel casing into each well, with cement on the            outside of the casing. The Company has fully complied with this environmental            regulation, the cost of which is approximately $10,000 per well.

 

The            State of Tennessee also requires the posting of a bond to ensure that the Company's            wells are properly plugged when abandoned. A separate $2,000 bond is required for each            well drilled. The Company currently has the requisite amount of bonds on            deposit.

 

As            part of the Company's purchase of the Kansas Properties it acquired a statewide permit            to drill in Kansas. Applications under such permit are applied for and issued within            one to two weeks prior to drilling. At the present time, the State of Kansas does not            require the posting of a bond either for permitting or to insure that the Company's            wells are properly plugged when abandoned. All of the wells in the Kansas Properties            have all permits required and the Company believes that it is in compliance with the            laws of the State of Kansas.

 

The            Company’s exploration, production and marketing operations are regulated            extensively at the federal, state and local levels. The Company has made and will            continue to make expenditures in its efforts to comply with the requirements of            environmental and other

 

14

 

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regulations. Further, the oil and gas regulatory environment could            change in ways that might substantially increase these costs. Hydrocarbon-producing            states regulate conservation practices and the protection of correlative rights. These            regulations affect the Company’s operations and limit the quantity of            hydrocarbons it may produce and sell. In addition, at the federal level, the Federal            Energy Regulatory Commission regulates interstate transportation of natural gas under            the Natural Gas Act. Other regulated matters include marketing, pricing, transportation            and valuation of royalty payments.

 

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

 

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

 

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

 

The            Company’s Board of Directors has adopted resolutions to form an Environmental            Response Policy and Emergency Action Response Policy Program. A plan was adopted which            provides for the erection of signs at each well and at strategic locations along the            pipeline containing telephone numbers of the Company's office. A list is maintained at            the Company's office and at the home of key personnel listing phone numbers for fire,            police, emergency services and Company employees who will be needed to deal with            emergencies.

 

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

 

15

 

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assurance can be given as to what affect 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. The Company, however, spent substantial amounts in            2006 and 2007 for the acquisition of seismic data relating to the Company’s            Kansas Properties and for three-dimensional analysis of the acquired seismic data for            the purpose of determining drilling targets with the maximum likelihood of being            commercial producers of oil when drilled.

 

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

 

The            Company presently has twenty-seven full time employees and one part-time            employee.

 

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**Executive Officers of the Registrant**

 

| **Identification of Executive                            Officers** |   |
|---------------------------------------------------------------------|--------|

 

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

 

| **Name**                                                                                                                                                                                                           | **Positions Held**                                                                                                                                   | **Date of Initial Election or                            Designation**                                                        |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------------|
| Jeffrey R. Bailey

2306 West Gallaher Ferry

Knoxville, TN 37932

                             

Charles Patrick McInturff

7500 San Felipe, Suite 400

Houston, TX 77063

                              | Chief Executive Officer1

                             

                             

                             

Vice-President | 6/17/02

                             

                             

                             

12/18/07 |   |
| Cary V. Sorensen

5517 Crestwood Drive

Knoxville, TN 37914                                                                                                                                                        | Vice-President;

General Counsel;

Secretary

                                                                                                  | 7/9/99                                                                                                                        |   |
| Mark A. Ruth

9400 Hickory Knoll Lane

Knoxville, TN 37931                                                                                                                                                         | Chief Financial Officer                                                                                                                              | 12/14/98                                                                                                                      |   |
|                                                                                                                                                                                                               |                                                                                                                                                 |                                                                                                                          |   |

 

 

| **Business                            Experience2** |  |
|-----------------------------------------------------|--|

 

Charles Patrick McInturff is 55 years old. Mr. McInturff received a            Bachelor of Science Degree in Civil Engineering from Texas A&M University in 1975.            He is a Registered Professional Engineer in Texas and a member of the Society of            Petroleum Engineers. Before joining the Company he was Vice President of Operations of            Capco Offshore, Inc. and related companies in Houston from October 2006 until December            2007 responsible for managing and supervising offshore operations and work-overs and            identification and evaluation of drilling and workover candidates. From 1991 to 2006,            he was employed by Ryder Scott Company in Houston performing reservoir studies            including determination of oil, gas, condensate and plant product reserves, enhanced            recovery and oil and gas property appraisal. For most of the period

_________________________

| 1 

Mr. Bailey is also a director of the                            Company. |   |
|-----------------------------------------------------------------------------------|--------|

2                       The background and business            experience of Jeffrey R. Bailey is incorporated by reference from the section entitled            “Proposal No. 1: Election of Directors” in the Company’s Proxy            Statement for the Company’s 2008 Annual Meeting of Stockholders.

 

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1978            to 1991, he worked in various petroleum engineering positions at Union Texas Petroleum            Corp. in Midland and Houston, Texas, and Karachi, Pakistan and was responsible for            surveillance and engineering on primary and secondary recovery projects as well as            design and field supervision of work-overs, pressure-transient tests and completions            both onshore and offshore. During that time period he also worked for Global Natural            Resources from 1983 to1986 as senior operations engineer responsible for all            engineering activities. From 1981 to 1983 he was employed by Belco Petroleum performing            reservoir engineering duties including field studies, economic evaluation, reserves            estimation, and initiating major field studies on waterflood projects in southwestern            Wyoming and west Texas. Mr. McInturff was employed by Exxon Co. USA from 1975 to 1978            primarily with the reservoir engineering group in Midland, Texas performing drilling            engineering duties including cost estimation, AFE preparation, drilling programs and            field supervision. He was responsible for the surveillance of fifteen Permian Basin oil            and gas fields in west Texas using both primary and secondary recovery techniques. On            December 18, 2007, he entered into a two-year employment agreement with the Company            pursuant to which he will serve as Vice-President of the Company.              

 

Cary            V. Sorensen is 59 years old. He is a 1976 graduate of the University of Texas School of            Law and has undergraduate and graduate degrees form North Texas State University and            Catholic University in Washington, D.C. Prior to joining the Company in July 1999, he            had been continuously engaged in the practice of law in Houston, Texas relating to the            energy industry since 1977, both in private law firms and a corporate law department,            serving for seven years as senior counsel with the litigation department of Enron Corp.            before entering private practice in June, 1996. He has represented virtually all of the            major oil companies headquartered in Houston as well as local distribution companies            and electric utilities in a variety of litigated and administrative cases before state            and federal courts and agencies in nine states. These matters involved gas contracts,            gas marketing, 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.

 

Mark            A. Ruth is 49 years old. He is a Certified Public Accountant with 27 years accounting            experience. He received a B.S. degree in accounting with honors from the University of            Tennessee at Knoxville. He has served as a project controls engineer for Bechtel Jacobs            Company, LLC; business manager and finance officer for Lockheed Martin Energy Systems;            settlement department head and senior accountant for the Federal Deposit Insurance            Corporation; senior financial analyst/internal auditor for Phillips Consumer            Electronics Corporation; and, as an auditor for Arthur Andersen and Company. On            December 14, 1998 he became the Company’s Chief Financial Officer.

 

| **Code of                            Ethics** |   |
|-----------------------------------------------|--------|

 

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

 

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and            Chief Financial Officer. The Company’s Board of Directors has also adopted a Code            of Conduct and Ethics for Directors, Officers and Employees. A copy of these codes can            be found at the Company's internet website at www.tengasco.com. The Company intends to            disclose any amendments to its Codes of Ethics, and any waiver from a provision of the            Code of Ethics granted to the Company's President, Chief Financial Officer or persons            performing similar functions, on the Company's internet website within five business            days following such amendment or waiver. A copy of the Codes of Ethics can be obtained            free of charge by writing to: Cary V. Sorensen, Secretary, Tengasco, Inc., 10215            Technology Drive, Suite 301, Knoxville, TN 37932.

 

**Available Information**

 

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

 

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

 

The            Company’s website is located athttp://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 1A.** | **RISK FACTORS** |
|--------------|------------------|

 

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

 

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 **The Company has a History of Significant            Losses****.**

During the early stages of the development of its oil and gas            business the Company has had a history of significant losses from operations, in            particular its development of the Swan Creek Field, and has an accumulated deficit of            $26,645,810 as of December 31, 2007. Although management has substantially reduced its            cash operating expenses, these losses have had a material adverse impact on the            operations of the Company’s business. The Company has been profitable in 2005,            2006, and 2007. However, in the event the Company experiences losses in the future it            may curtail the Company’s development activities or force the Company to sell            some of its assets in an untimely fashion or on less than favorable terms.

**The Company’s Credit Facility with Sovereign Bank****Is Subject to Variable Rates of Interest,**

**Which Could** **Negatively Impact the Company.**

 

Borrowings under the Company’s credit facility with Sovereign Bank            of Dallas, Texas (“Sovereign Bank”) are at variable rates of interest and            expose the Company to interest rate risk. If interest rates increase, the            Company’s debt service obligations on the variable rate indebtedness would            increase even though the amount borrowed remained the same, and its net income and cash            flows would decrease. The Company’s credit facility agreement contains certain            financial covenants based on the Company’s performance. If the Company’s            financial performance results in any of these covenants being violated, Sovereign Bank            may choose to require repayment of the outstanding borrowings sooner than currently            required by the agreement.

             

             

| **                           ** |   |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|

**The Company’s Borrowing Base under its **Credit Facility may be reduced by Sovereign            Bank****.

The borrowing base under the Company’s revolving credit facility            with Sovereign Bank will be determined from time to time by the lender, consistent with            its customary natural gas and crude oil lending practices. Reductions in estimates of            the Company’s natural gas and crude oil reserves could result in a reduction in            the Company’s borrowing base, which would reduce the amount of financial            resources available under the Company’s revolving credit facility to meet its            capital requirements. Such a reduction could be the result of lower commodity prices or            production, inability to drill or unfavorable drilling results, changes in natural gas            and crude oil reserve engineering, the lenders' inability to agree to an adequate            borrowing base or adverse changes in the lenders' practices regarding estimation of            reserves. If cash flow from operations or the Company’s borrowing base decrease            for any reason, the Company’s ability to undertake exploration and development            activities could be adversely affected. As a result, the Company’s ability to            replace production may be limited. In addition, if the borrowing base under the            Company’s Sovereign Bank revolving credit facility is reduced, it would be            required to pay down its borrowings under the revolving credit facility so that            outstanding borrowings do not exceed the reduced borrowing base. This could further            reduce the cash available to the Company for capital spending and, if the Company did            not have sufficient capital to reduce its borrowing

 

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level, could cause the Company to default under its revolving credit            facility with Sovereign Bank.

             

|   |   |
|--------|--------|

| **                  ** |   |
|------------------------------------------------------------------------------------------------------------------|--------|

**Declines In Oil or Gas Prices Will Materially**Adversely Affect the Company’s            Revenues.****

 

The            Company’s future financial condition and results of operations will depend in            large 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.            Although oil prices are currently at record high levels which has had a substantial            favorable impact on the Company’s revenues, there can be no assurances that            prices will remain at the current rates or continue to increase as they have during the            past year. A substantial or extended decline in oil or 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.

 

|   |  |
|--------|--|

| **                          ** |  |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------|--|

|   |  |
|--------|--|

**Risks In Rates Of Oil and Gas Production,            **Development Expenditures, and Cash Flows            May****

******Have a Substantial Impact            on the Company’s Finances.******

             

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 which would have a significant impact on the            Company’s financial position.

 

|   |  |
|--------|--|

****The Company’s Oil and Gas            Operations** Involve Substantial Costs and are**

**Subject**to Various Economic            Risks**.**

             

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|   |  |
|--------|--|

****Shortages of Oil Field Equipment, Services            and** Qualified Personnel Could Adversely**

**Affect the** **Company’s Results of Operations.**

 

The            demand for qualified and experienced field personnel to drill wells and conduct field            operations, geologists, geophysicists, engineers and other professionals in the oil and            natural gas industry can fluctuate significantly, often in correlation with oil and            natural gas prices, causing periodic shortages. The Company does not own any drilling            rigs and is dependent upon third parties to obtain and provide such equipment as needed            for the Company’s drilling activities. There have also been shortages of drilling            rigs and other equipment as oil prices have risen and as a result the demand for rigs            and equipment increased along with the number of wells being drilled. These factors            also cause significant increases in costs for equipment, services and personnel. Higher            oil and natural gas prices generally stimulate increased demand and result in increased            prices for drilling rigs, crews and associated supplies, equipment and services. These            shortages or price increases could adversely affect the Company’s profit margin,            cash flow, and operating results or restrict the Company’s ability to drill wells            and conduct ordinary operations.

 

|   |   |
|--------|--------|

|   |   |
|--------|--------|

**The Company’s Failure to Find or Acquire            Additional **Reserves Will Result in the Decline of            the****

****Company’s **Reserves            Materially From Their Current Levels.******

             

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

 

In            addition, the Company’s drilling for oil and natural gas may involve unprofitable            efforts not only from dry wells but also from wells that are productive but do not            produce sufficient net reserves to be commercially profitable after deducting drilling,            operating, and other costs. In addition, wells that are profitable may not achieve a            targeted rate of return. The Company relies on seismic data and other technologies in            identifying prospects and in

 

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conducting exploration activities. The seismic data and other            technologies used do not allow them to know conclusively prior to drilling a well            whether oil or natural gas is present or may be produced economically.

 

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

 

**The Company’s Reserve Estimates May Be Subject**

**to Other Material Downward            Revisions****.**

 

The            Company’s oil reserve estimates or gas reserve estimates may be subject to            material downward revisions for additional reasons other than the factors mentioned in            the previous risk factor entitled “The Company’s Failure to Find or Acquire            Additional Reserves Will Result in the Decline of the Company’s Reserves            Materially from Their Current Levels.” While the future estimates of net cash            flows from the Company’s proved reserves and their present value are based upon            assumptions about future production levels, prices, and costs that may prove to be            incorrect over time, those same assumptions, whether or not they prove to be correct,            may cause the Company to make drilling or developmental decisions that will result in            some or all of the Company’s proved reserves to be removed from time to time from            the proved reserve categories previously reported by the Company. This may occur            because economic expectations or forecasts, together with the Company’s limited            resources, may cause the Company to determine that drilling or development of certain            of its properties may be delayed or may not foreseeably occur, and as a result of such            decisions any category of proved reserves relating to those yet undrilled or            undeveloped properties may be removed from the Company’s reported proved            reserves. Consequently, the Company’s proved reserves of oil or of gas, or both,            may be materially revised downward from time to time. As an example, the            Company’s proved Swan Creek gas reserves have been revised downward in the past            few years as a result of removal of portions of the Company’s reported gas            reserves from the “proved undeveloped category (“PUD”) and the            “proved developed nonproducing” (“PDNP”) categories because of            the Company’s determination that additional drilling or development of Swan Creek            may not occur in the foreseeable future based on the Company’s determination that            the economic returns from such drilling or development would not be favorable when            compared to the costs and anticipated results of such activity. Although that            particular revision at this time will not have a significant impact on overall results            of operations in view of the relatively small portion of the Company’s current            business and assets founded in natural gas (as opposed to oil where reserves have been            materially revised upward in the same period), other revisions in gas reserves, or in            oil reserves, in the future may be significant and materially reduce oil or gas            reserves. In addition, the Company may elect to sell some or all of its oil or gas            reserves in the normal course of the Company’s

             

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****There is Risk that the Company may be**            Required to Write-Down the Carrying**

**Value****of its Natural Gas****and Crude Oil Properties**.

 

The            Company uses the full cost method to account for its natural gas and crude oil            operations. Accordingly, the Company capitalizes the cost to acquire, explore for and            develop natural gas and crude oil properties. Under full cost accounting rules, the net            capitalized cost of natural gas and crude oil properties may not exceed a "ceiling            limit" which is based upon the present value of estimated future net cash flows from            proved reserves, discounted at 10%. If net capitalized costs of natural gas and crude            oil properties exceed the ceiling limit, the Company must charge the amount of the            excess to earnings. This is called a "ceiling limitation write-down." This charge does            not impact cash flow from operating activities, but does reduce the Company’s            stockholders' equity and earnings. The risk that the Company will be required to            write-down the carrying value of natural gas and crude oil properties increases when            natural gas and crude oil prices are low. In addition, write-downs may occur if the            Company experiences substantial downward adjustments to its estimated proved reserves.            An expense recorded in one period may not be reversed in a subsequent period even            though higher natural gas and crude oil prices may have increased the ceiling            applicable to the subsequent period. The Company has not incurred ceiling limitation            write-downs in the past. However, we cannot assure you that the Company will not            experience ceiling limitation write-downs in the future.

 

**Use            of the Company’s Net Operating Loss Carryforwards may be limited.**

At            December 31, 2007, The Company had, subject to the limitations discussed in this risk            factor, substantial amounts of Net Operating Loss Carryforwards for U.S. federal income            tax purposes. These loss carryforwards will eventually expire if not utilized. In            addition, as to a portion of the U.S. net operating loss carryforwards, the amount of            such carryforwards that the Company can use annually is limited under U.S. tax laws.            Uncertainties exist as to both the calculation of the appropropiate deferred tax assets            based upon the existence of these loss carryforwards, as well as the future utilization            of the operating loss carryforwards under the criteria set forth under FASB Statement            No. 109. In addition, limitations exist upon use of these carryforwards in the event of            a change in control of the Company occurs. There are risks that the Company may not be            able to utilize some or all of the remaining carryforwards, or that deferred tax assets            that were previously booked based upon such carryforwards may be written down or            reversed based on future economic factors that may be experienced by the Company. The            effect of such writedowns or reversals, if they occur, may be material and            substantially adverse.

 

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**The Company has Significant Costs to Conform            to**

****Government Regulation of the Oil            and Gas Industry****.****

             

The Company’s exploration, production, and marketing operations            are regulated extensively at the federal, state and local levels. The Company is            currently in compliance with these regulations. In order to maintain its compliance,            the Company has made and will have to continue to make substantial 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.

 

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****The Company also has Significant            Costs** Related to Environmental            Matters****.**

 

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 owned or            leased, properties that have been leased for the exploration and production of oil and            gas and these properties and the wastes disposed on these properties may be subject to            the Comprehensive Environmental Response, Compensation and Liability Act, the Oil            Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water            Pollution Control Act and similar state laws. Under such laws, the Company could be            required to remove or remediate wastes or property contamination.

 

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

 

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

 

| **Insurance Does Not Cover All                            Risks.**  |   |
|--------------------------------------------------------------------------|--------|

 

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Exploration for and production of oil and natural gas and the            Company’s transportation and other activities 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 to 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’s****Methane            Extraction from Non-conventional****Reserves Operations            Involve Substantial Costs and are Subject**

**to Various Economic, Operational, and Regulatory            Risks****.**

 

The            Company’s operations in projects involving the extraction of methane gas from            non-conventional reserves such as landfill gas streams, require investment of            substantial capital and are subject to the risks typically associated with capital            intensive operations, including risks associated with the availability of financing for            required equipment, construction schedules, air and water environmental permitting, and            locating transportation facilities and customers for the products produced from those            operations which may delay or prevent startup of such projects. After startup of            commercial operations, the presence of unanticipated pressures or irregularities in            constituents of the raw materials used in such projects from time to time,            miscalculations or accidents may cause the Company’s project activities to be            unsuccessful. Although the technologies to be utilized in such projects is believed to            be effective and economical, there are operational risks in the use of such            technologies in the combination to be utilized by the Company as a result of both the            combination of technologies and the early stages of commercial development and use of            such technologies for methane extraction from non-conventional sources such as those to            be used by the Company. These risks could result in a total or partial loss of the            Company’s investment in such projects. The economic risks of such projects            include the marketing risks resulting from price volatility of the methane gas produced            from such projects, which is similar to the price volatility of natural gas. These            projects are also subject to the risk that the products manufactured may not be            accepted for transportation in common carrier gas transportation facilities although            the products meet specified requirements for such transportation, or may be accepted on            such terms that reduce the returns of such projects to the Company. These projects are            also subject to the risk that the product manufactured may not be accepted by            purchasers thereof from time to time and the viability of such projects would be            dependent upon the Company’s ability to locate a replacement market for physical            delivery of the gas produced from the project.

 

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**The Company is Not Competitive            with**

****Respect to Acquisitions or            Personnel.****

             

The oil and gas business is highly competitive. In seeking any suitable            oil and gas properties for acquisition, or drilling rig operators and related personnel            and equipment, the

 

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Company is a small entity with limited financial resources and may not            be able to compete with most other companies, including large oil and gas companies and            other independent operators with greater financial and technical resources and longer            history and experience in property acquisition and operation.

 

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**The Company Depends on Key            Personnel,**

****Whom it May Not be Able to Retain            or Recruit.****

             

Jeffrey R. Bailey, the Company’s Chief Executive Officer, other            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.

 

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****The Company’s Operations are Subject            to** Changes in the 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.

 

**Being a Public Company Significantly Increases**

****the Company’s Administrative            Costs****.****

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The            Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and            listing requirements subsequently adopted by the American Stock Exchange in response to            Sarbanes-Oxley, have required changes in corporate governance practices, internal            control policies and audit committee practices of public companies. Although the            Company is a relatively small public company these rules, regulations, and requirements            for the most part apply to the same extent as they apply to all major publicly traded            companies. As a result, they have significantly increased the Company’s legal,            financial, compliance and administrative costs, and have made certain other activities            more time consuming and costly, as well as requiring substantial time and attention of            our senior management. The Company expects its continued compliance with these and            future rules and regulations to continue to require significant resources. These rules            and regulations also may make it more difficult and more expensive for the Company to            obtain director and officer liability insurance in the future, and could make it more            difficult for it to attract and retain qualified members for the Company’s Board            of Directors, particularly to serve on its audit committee.

 

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**The Company’s Chairman of the Board Beneficially            Owns****A Substantial Amount of the Company’s Common            Stock**

**And Has Significant Influence over the Company’s            Business**.

Peter E. Salas, the Chairman of the Company’s Board of Directors,            is the sole shareholder and controlling person of Dolphin Management, Inc., the general            partner of Dolphin Offshore Partners, L.P., which is the Company’s largest            shareholder. At December 31, 2007, Mr. Salas, directly and through Dolphin owned            21,057,492 shares of the Company’s common stock and had options granting him the            right to acquire an additional 50,000 shares of common stock. His ownership and voting            control over approximately 36% of the Company’s common stock gives him            significant influence on the outcome of corporate transactions or other matters            submitted to the Board of Directors or shareholders for approval, including mergers,            consolidations and the sale of all or substantially all of the Company’s            assets.

 

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****Shares Eligible for Future Sale            may ** Depress the Company’s Stock            Price**.

             

As of March 3, 2008, the Company had 59,155,750 shares of common stock            outstanding of which 21,654,879 shares were held by affiliates and, in addition,            2,841,000 shares of common stock were subject to outstanding options granted under the            Tengasco, Inc. Stock Incentive Plan (of which 1,627,000 shares were vested at March 3,            2008).

             

All of the shares of common stock held by affiliates are restricted or            controlled securities under Rule 144 promulgated under the Securities Act of 1933, as            amended (the "Securities Act"). The shares of the common stock issuable upon exercise            of the stock options have been registered under the Securities Act. Sales of shares of            common stock under Rule 144 or another exemption under the Securities Act or pursuant            to a registration statement could have a material adverse effect on the price of the            common stock and could impair the Company’s ability to raise additional capital            through the sale of equity securities.

 

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**Future Issuance of Additional Shares of the            Company’s**

****Common Stock could cause Dilution            of Ownership**Interests and Adversely Affect Stock            Price****.******

             

The Company may in the future issue previously authorized and unissued            securities, resulting in the dilution of the ownership interests of its current            stockholders. The Company is currently authorized to issue a total of 100,000,000            shares of common stock with such rights as determined by the Board of Directors. Of            that amount, approximately 59 million shares have been issued. The potential issuance            of the approximately 41 million remaining authorized but unissued shares of common            stock may create downward pressure on the trading price of the Company’s common            stock. The Company may also issue additional shares of its common stock or other            securities that are convertible into or exercisable for common stock for capital            raising or other business purposes. Future sales of substantial amounts of common            stock,

 

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or            the perception that sales could occur, could have a material adverse effect on the            price of the Company’s common stock.

 

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**The Company may Issue Shares of Preferred            Stock**

****With Greater Rights than Common            Stock****.****

             

Subject to the rules of The American Stock Exchange, the Company’s            charter authorizes the board of directors to issue one or more series of preferred            stock and set the terms of the preferred stock without seeking any further approval            from holders of the Company’s common stock. Any preferred stock that is issued            may rank ahead of the Company’s common stock in terms of dividends, priority and            liquidation premiums and may have greater voting rights than the Company’s common            stock.

 

                

| **ITEM 1B.** | **UNRESOLVED STAFF COMMENTS** |
|--------------|-------------------------------|

 

| Not Applicable |   |
|----------------|--------|

             

             

| **ITEM 2.** | **PROPERTIES** |
|-------------|----------------|

 

**Property Location, Facilities, Size and Nature of            Ownership**

 

| **General** |   |
|-------------|--------|

 

The            Company leases its principal executive offices, consisting of approximately 4,607            square feet located at 10215 Technology Drive, Suite 301, Knoxville, Tennessee at a            rental of $5,279 per month and an office in Hays, Kansas at a rental of $500 per month.            The Company has leased office space in Houston, Texas for use by Patrick McInturff, a            vice president of the Company, at a rental of $1,000 per month.

 

Although the Company does not pay taxes on its Swan Creek leases, it            pays ad-valorem taxes on its Kansas Properties. The Company has general liability            insurance for its Kansas and Tennessee Properties. The Company does not yet have            production interest in Texas, but it is anticipated that an opportunity to participate            in the properties the Company manages on behalf of Hoactzin Partners, L.P. will be            available in the future.

 

| **Kansas                            Properties** |   |
|--------------------------------------------------|--------|

 

The            Kansas Properties as of December 31, 2007 contained 192 leases totaling 28,934 acres in            the vicinity of Hays, Kansas. The increase in the total volume of acreage of the            Company’s Kansas Properties from 27,837 acres at the end of 2006 is primarily due            to the purchase of two producing leases, the Heyl and RJ Thyfault. The Company focused            its drilling, development, and exploration activities in Kansas in 2007 on evaluation            of older producing

 

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properties, and those properties acquired in 2005 and 2006. Many of            these leases, however, are still in effect because they are being held by production.            The leases provide for a landowner royalty of 12.5%. Some wells are subject to an            overriding royalty interest from 0.5% to 9%. The Company maintains a 100% working            interest in most of its older wells and any undrilled acreage in Kansas. The terms for            most of the Company’s newer leases in Kansas are from three to five            years.

 

Kansas            as a whole is of major significance to the Company. The majority of the Company’s            current reserve value, current production, revenue, and future development objectives            are centered in the Company’s ongoing interests in Kansas. By using 3-D seismic            evaluation on existing locations owned by the Company in Kansas, the Company has added            and continues to add proven direct offset locations. As a result of recent higher            commodity prices for its oil, the Company has been able to drill from cash flow and            attract favorable drilling partner programs in which the Company retains not only a            carried beginning interest but a higher-than-industry-standard reversionary interest.            The Company expects to continue this mix of company drilling and program drilling            depending primarily on future cash flow and future oil prices. Breaking down the            Company’s assets in Kansas into individual leases produces no apparent stand out            leases that appear to be stand-alone principal properties. As a whole, however, our            collective central Kansas holdings (see map below) are of major significance and as a            group the most materially important segment of the Company as demonstrated by the            following facts during the year ending December 31, 2007:

 

**•**          Kansas            accounted for 91.4% of the Company’s revenue (i.e. $8,560,097 of            $9,368,624.)

**•**          Kansas            accounted for 86% of the Company’s total production measured in BOE (Barrel of            Oil Equivalent)

**•**          Kansas            contributes $14.791 million in value of future proven development locations as of year            end 2007, compared to just $567,000 in Tennessee

**•**          The            Company’s focus in 2008 will be to continue with offset seismic development, and            leasing activity in Kansas. As a result, the Company’s undeveloped location value            and total number of locations are expected to grow.

 

The map below indicates the location of the Company’s top six            valued leases in Kansas as of December 31, 2007.

 

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The following tables indicate the production from the Company’s            top six leases in 2007 as well as the reserve value of these leases as of December 31,            2007. By comparing these tables with the tables below showing the total production from            the Kansas Properties in 2007 and the Company’s aggregate reserve value as of            December 31, 2007, it is apparent that none of the Company’s Kansas leases are on            their own significant properties, but that they must all be viewed as a whole to            appreciate their significance to the Company’s operations.

 

 

**Largest Kansas Leases by Production**

 

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|   | **Total Oil Production 2007** | **185,188 Barrels**               |
|--------|-------------------------------|-----------------------------------|
|   | **LEASE**                     | **2007 Gross Production barrels** | **Company Net Revenue Interest** | **Percentage of Total Oil Production** |
| 1      | Croffoot B                    | 11,509                            | 0.8203124 | 6% |
| 2      | Harrison A                    | 9,537                             | 0.875 | 5% |
| 3      | Stahl                         | 7,407                             | 0.84375 | 4% |
| 4      | Croffoot                      | 7,360                             | 0.861328 | 4% |
| 5      | Lewis                         | 4,994                             | 0.875 | 3% |
| 6      | Kraus A                       | 4,239                             | 0.8203125 | 2% |

 

 

 

 

 

 

 

 

 

 

|   | (All Reserve Values are Stated in $1000's)

(ALL “VALUES” ARE STATED IN STANDARDIZED                            MEASURE OF FUTURE CASH FLOWS) |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |  

**Value Of Company Proved Reserves**

                                                                                                       | **$53,627,085** |
| Map #  | **LEASE**

(Number of Producing Wells)                                                                                                                    | **Proved Producing Value** | **Proved Undeveloped**

**Value** | **Lease Total Value** | **Percentage of Total Lease Value to Company Proved                            Reserves** |
|        |                                                                                                                                                           |  |  |  |  |

 

 

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| 1 | Croffoot (4)   | $2,210.84 | $1,322,99 | **$3,533.84** | 7% |
|---|----------------|-----------|-----------|---------------|----|
| 2 | Harrison A (5) | $2,205.43 | $502.97   | **$2,708.40** | 5% |
| 3 | Lewis (3)      | $1,522.53 | $943.85   | **$2,466.38** | 5% |
| 4 | Croffoot B (6) | $1,646.58 | $733.52   | **$2,380.10** | 4% |
| 5 | Kraus A (4)    | $1,473.18 | $377.73   | **$1,850.91** | 3% |
| 6 | Stahl (4)      | $1,249.79 | $401.24   | **$1,651.03** | 3% |

**Largest Kansas Lease by Reserve Value**

 

 

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**Tennessee Properties**

The Company's Swan Creek leases are on approximately 6,675 acres in            Hancock, Claiborne and Jackson Counties in Tennessee. The decrease in the total volume            of acreage of the Company’s Swan Creek leases from 8,635 acres at the end of 2006            is primarily due to the Company not renewing leases that were not in production. The            initial terms of the Company’s Swan Creek leases vary from one to five            years.

 

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

 

**Reserve Analyses**

 

The            Company’s estimated total net proved reserves of oil and natural gas as of            December 31, 2007, and the present values of estimated future net revenues            attributable to those reserves as of those dates, are presented in the following table.            These estimates were prepared by LaRoche Petroleum Consultants, Ltd.            (“LaRoche”) of Houston, Texas, and are part of their reserve reports on the            Company’s oil and gas properties. LaRoche and its employees and its registered            petroleum engineers have no interest in the Company and performed those services at            their standard rates. Laroche’s estimates were based on a review of geologic,            economic, ownership and engineering data that they were provided by the Company. In            estimating the reserve quantities that are economically recoverable, end-of-period            natural gas and oil prices, held constant, were used. In accordance with SEC            regulations, no price or cost escalation or reduction was considered.

             

 

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|                                                                                    |              |                                                                                                                  |              |                   |              |                 |              |           |            |              |        |            |
|------------------------------------------------------------------------------------|--------------|------------------------------------------------------------------------------------------------------------------|--------------|-------------------|--------------|-----------------|--------------|-----------|------------|--------------|--------|------------|
|                                                                               |    | **Total Proved Reserves as of                            December** **31,                            2007** |
|                                                                               |    | **Producing**                                                                                                    |    | **Non-producing** |    | **Undeveloped** |    | **Total** |
| Natural gas (MMcf)                                                                 |    |                                                                                                             | 1,130        |         |         | 3.528           |    |      | 0          |              |   | 1,134      |
| Oil (Bbls)                                                                         |    |                                                                                                             | 1,604,607    |         |         | 7,726           |              |           | 663,637    |              |        | 2,275,970  |
| Total proved reserves (BOE)                                                        |    |                                                                                                             | 1,792,940    |                   |         | 8,314           |              |           | 663,637    |              |        | 2,464,970  |
| Standardized measure of discounted future net cash                            flow |    |                                                                                                                  | $37,803,144  |         | $            | 466,726         |    | $         | 15,357,217 |    | $      | 53,627,086 |
|                                                                                    |              |                                                                                                                  |              |                   |              |                 |              |           |            |              |        |            |  |

             

SEC regulations require that the natural gas and oil prices used in            Laroche’s reserve reports are the period-end prices for natural gas and oil at            December 31, 2007. These prices are held constant in accordance with SEC            guidelines for the life of the wells included in the reserve reports but are adjusted            by lease for energy content, quality, transportation, compression and gathering fees,            and regional price differentials. The weighted average oil and natural gas prices after            basis adjustments used in our reserve valuation as of December 31, 2007 were            $85.44 per barrel and $7.21 per Mcf.

The prices used in calculating the estimated future net revenue            attributable to proved reserves do not reflect market prices for natural gas and oil            production sold subsequent to December 31, 2007. There can be no assurance that            all of the estimated proved reserves will be produced and sold at the assumed prices.            Accordingly, the foregoing prices should not be interpreted as a prediction of future            prices.

The standardized measure of future net cash flows associated with total            proved reserves as of December 31, 2007 is stated to be $53,627,086. The LaRoche Report            indicates the “proven developed producing” reserves for the Company as of            December 31, 2007 to be as follows: net production volumes of 1,604,607 barrels of oil            and 1,130 MMCF of gas compared to 1,358,532 barrels of oil and 1,264 MMCF of gas as            reported by the Company at the end of 2006. The standardized measure of future net cash            flows associated with total proved producing reserves as of December 31, 2007 is stated            to be $37,803,144. The increase in oil reserves from 2006 to 2007 is reflective of the            Company’s increased drilling activities in Kansas in 2007 and future drilling            plans including 39 future wells at proved undeveloped (PUD) locations. The decrease in            gas reserves from 2005 is due primarily to the Company’s determination not to            drill any new wells in its Swan Creek Field and the drop in the price used to calculate            the gas reserves from $8.33 per Mcf in 2006 to $7.21 per Mcf in 2007. For additional            information concerning our estimated proved reserves, the standardized measure of            discounted future net cash flows of the proved reserves at December 31, 2007, 2006            and 2005, and the changes in quantities and standardized measure of such reserves for            each of the three years then ended; see Note 20 to our consolidated financial            statements.

 

In            substance, the LaRoche 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,

 

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state regulatory agencies, commercial services, outside operators and            files of LaRoche.  The net reserve values in the Report were adjusted to take into            account the working interests that have been sold by the Company in various            wells.

 

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

 

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

 

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

 

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

 

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

 

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

             

37

 

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testing by a pilot project, or the operation of an installed program in            the reservoir, provides support for the engineering analysis on which the project or            program was based.

 

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

             

**Production**

 

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

 

| **KANSAS**                      |
|---------------------------------|
| **Year Ended December**

**31** | **Production** | **Cost of**

**Production**

**(per BOE)3** | **Average Sales Price** |
|                            | **Oil**

**(Bbl)** | **Gas**

**(Mcf)4** |   | **Oil**

**(Bbl)** | **Gas**

**(Per Mcf)** |
| **2007**                        | 178,311 | -0- | $16.97 | $85.53 | -0- |
| **2006**                        | 179,556 | -0- | $13.05 | $56.69 | -0- |
| **2005**                        | 128,765 | 20,729 | $15.33 | $53.48 | $5.02 |

 

| **TENNESSEE**                   |
|---------------------------------|
| **Year Ended December**

**31** | **Production** | **Cost of**

**Production**

**(per BOE)** | **Average Sales Price** |
|                            | **Oil**

**(Bbl)** | **Gas**

**(Mcf)** |   | **Oil**

**(Bbl)** | **Gas**

**(Per Mcf)** |
| **2007**                        | 6,877 | 117,129 | $26.42 | $82.71 | $7.21 |
| **2006**                        | 9,633 | 138,078 | $14.97 | $54.81 | $8.33 |

_________________________

3                       A “BOE is a barrel of            oil equivalent. A barrel of oil contains approximately 6 Mcf of natural gas by heating            content. The volumes of gas produced have been converted into “barrels of oil            equivalent” for the purposes of calculating costs of production.

4                       Figures in this column            reflect the fact that the Company sold all of the gas producing wells on its Kansas            Properties on March 4, 2005 effective as of February 1, 2005. Thus, gas production is            only through January 2005.

 

38

 

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| **2005** | 10,818 | 183,400 | $18.86 | $53.90 | $8.74 |
|----------|--------|---------|--------|--------|-------|

 

**Oil and Gas Drilling Activities**

 

| **Kansas** |   |
|------------|--------|

 

In            2007, the Company drilled 16 new wells in Kansas, 15 of which were drilled in the third            and fourth quarters. These wells included nine wells drilled in the Ten Well Program.            The Company has a 100% working interest in the remaining seven wells drilled in Kansas            in 2007. All wells drilled in 2007 have produced in the aggregate a cumulative total of            6,215 barrels of oil.

 

The            results of the wells drilled in Kansas as of December 31, 2007 are set out in the            following table. Unless otherwise indicated the Company has a 100% working interest in            the wells.

 

|  

**NAME OF**

**WELL** |  

**DATE****COMPLETED** |  

**CUMULATIVE PRODUCTION (Bbl)** |
|-------------------------------|-------------------------------|-----------------------------------------|
| Mai #1                        | 2-18-07                       | Dry Hole – Plugged (exploratory)  |
| Lowry B #1                    | 5-22-07                       | Dry Hole – Plugged                |
| Dirks #2                      | 7-9-2007                      | 749.00                                  |
| Howard #1                     | 7-5-07                        | Dry Hole – Plugged (exploratory)  |
| Hobrock #5                    | 8-7-2007                      | 1817.00                                 |
| Veverka #1                    | 8-17-07                       | Dry Hole – Plugged                |
| Gilliland #1                  | 8-28-07                       | Dry Hole – Plugged (exploratory)  |
| Stahl A #1                    | 10-16-2007                    | 795.00*                                 |
| Croffoot AA #1                | 10-19-2007                    | 1285.00*                                |
| Veverka A #1                  | 11-16-2007                    | 75.00*                                  |
| Croffoot BB #1                | 11-15-2007                    | 863.00*                                 |
| Howard #2                     | 11-8-07                       | Dry Hole – Plugged* (exploratory) |
| Nutsch #1                     | 12-6-2007                     | 631.00*                                 |
| Green #1                      | 12-27-2007                    | 0* (Exploration Discovery)              |
| Veverka A #2                  | 1-4-2008                      | 0*                                      |
| McElaney #1                   | 1-24-08                  | 0*(Exploration Discovery)               |
|                          |                          |                                    |

 

| * | Part of the Ten Well Program |
|---|------------------------------|

 

 

39

 

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

 

 

|   | **Tennessee**   |
|--------|---------------------------|

 

In            2007, the Company did not drill any new wells in the Swan Creek Field. The Company has            signed a farmout agreement allowing the drilling of shale gas wells in leased areas            surrounding the Swan Creek Field. The Company believes that drilling new gas wells in            the Field will not contribute to achieving any significant increase in daily gas            production totals from the Field. As a result, the Company does not have any plans at            the present time to drill any new gas wells in the Swan Creek Field.

 

|   | **Gross and Net Wells** |
|--------|-------------------------|

 

The            following tables set forth for the fiscal years ending December 31, 2005, 2006, and            2007 the number of gross and net development wells drilled by the Company. The wells            drilled in 2007 refer to the nine wells drilled in the Ten Well Program as well as            seven other wells drilled in Kansas in which the Company has a 100% working interest.            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** |
|----------------------------|
|                       | **2007** | **2006** | **2005** |
|                       | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| **Kansas**                 |
| **Productive Wells**       | 10 | 4.0 | 9 | 5.055 | 7 | 0.9175 |
| **Dry Holes**              | 6 | 5.25 | 1 | .056 | 2 | 0.2163 |
| **Tennessee**              |
| **Productive Wells**       | 0 | 0 | 0 | 0 | 0 | 0 |
| **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, 2007. 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** |
|--------|---------|---------|

 

 

40

 

----

 

|          | **Gross** | **Net** | **Gross** | **Net** |
|---------------|-----------|---------|-----------|---------|
| **Kansas**    | 0         | 0       | 182       | 142     |
| **Tennessee** | 21        | 16.3    | 4         | 3.5     |

 

 

 

**Developed and Undeveloped Oil and Gas Acreage**

 

As            of December 31, 2007, the Company owned working interests in the following developed            and undeveloped oil and gas acreage. Net acres refer to the Company’s interest            less the interest of royalty and other working interest owners.

 

|          | **DEVELOPED**   | **UNDEVELOPED** |
|---------------|-----------------|-----------------|
|          | **Gross Acres** | **Net Acres**   | **Gross Acres** | **Net Acres** |
| **Kansas**    | 12,150          | 10,002          | 16,784 | 13,285 |
| **Tennessee** | 1,525           | 1,250           | 5,151 | 4,224 |

             

| **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 2007. |
|--------|-----------------------------------------|

 

**PART II**

 

| **ITEM 5.** | **MARKET FOR REGISTRANT’S COMMON                            EQUITY,** |
|-------------|-----------------------------------------------------------------------------|

|   | **RELATED STOCKHOLDER MATTERS AND ISSUER** |
|--------|--------------------------------------------|

|   | **PURCHASES OF EQUITY SECURITIES** |
|--------|------------------------------------|

 

| **Market Information** |
|------------------------|

 

 

41

 

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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, 2007            and December 31, 2006 are set forth below.

             

| **High**                    | **Low**                 |
|-----------------------------|-------------------------|
| **For the Quarters Ending** |
| March 31, 2007              | $   0.83 | $   0.69 |
| June 30, 2007               | 0.76                    | 0.59 |
| September 30, 2007          | 0.80                    | 0.59 |
| December 31, 2007           | 0.81                    | 0.50 |
|                        |
| March 31, 2006              | $   1.18 | $   0.42 |
| June 30, 2006               | 1.93                    | 1.02 |
| September 30, 2006          | 1.41                    | 0.71 |
| December 31, 2006           | 1.05                    | 0.70 |

 

 

42

 

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**Holders**

 

As            of March 3, 2008 the number of shareholders of record of the Company's common stock was            333 and management believes that there are approximately 6,133 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            2007 and has no present plans to declare any further dividends with respect to its            common stock.

 

**Recent Sales of Unregistered Securities**

 

During the fourth quarter of fiscal 2007, the Company issued 6,832            shares of its common stock pursuant to the exercise of warrants issued by the Company            to a member of the plaintiff class as part of the settlement of the action            entitled*Paul Miller v. M. E. Ratliff and Tengasco,            Inc.*, United States District Court for the Eastern District            of Tennessee, Knoxville, Docket Number 3:02-CV-644. Those warrants are exercisable for            a period of three years from date of issue at $0.45 per share and are exempt from            registration pursuant to section 3(a) (10) of the Securities Act of 1933, as amended.            Any unregistered equity securities that were sold or issued by the Company during the            first three quarters of Fiscal 2007 were previously reported in Reports filed by the            Company with the SEC.

 

**Purchases of Equity Securities by the Company**

**And Affiliated Purchasers** 

 

Neither the Company nor any of its affiliates repurchased any of the            Company’s equity securities during 2007.

 

**Equity Compensation Plan Information**

 

See            Item 12, “Security Ownership of Certain Beneficial Owners and Management and            Related Stockholder Matters” for information regarding the Company’s equity            compensation plans.

 

**Performance Graph**

 

The            graph below compares the cumulative total stockholder return on the Company’s            common stock with the cumulative total stockholder return of (1) the American Stock            Exchange Index and (2) the Standard Industrial Code Index for the Crude Petroleum and            Natural Gas Industry, assuming an investment in each of $100 on December 31, 2002. The            performance graph represents past performance and should not be considered to be an            indication of future performance.

 

43

 

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**COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE**

**COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD            MARKETS**

 

| **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.

 

Year            Ended December 31,

 

|                                                                                    | **2007**                                                                | **2006**                                                          | **2005**                                                    | **2004**                                                | **2003**                                                      |
|-----------------------------------------------------------------------------------------|-------------------------------------------------------------------------|-------------------------------------------------------------------|-------------------------------------------------------------|---------------------------------------------------------|---------------------------------------------------------------|
| **Income Statement Data:**                                                              |                                                                    |                                                              |                                                        |                                                    |                                                          |
| Oil and Gas Revenues                                                                    | $9,300,144                                                              | $8,896,036                                                        | $7,067,790                                                  | $6,013,374                                              | $6,040,872                                                    |
| Production Cost and Taxes                                                               | $4,322,833                                                              | $3,287,233                                                        | $3,046,460                                                  | $3,364,429                                              | $3,412,201                                                    |
| General and

Administrative                                                             | $1,417,001                                                              | $1,293,109                                                        | $1,322,616                                                  | $1,777,183                                              | $1,486,280                                                    |
| Interest Expense                                                                        | $   333,198                                              | $   168,590                                        | $ 472,655                                                   | $1,367,180                                              | $1,120,738                                                    |
| Net Income/Loss                                                                         | $3,510,322                                                              | $2,141,364                                                        | $1,088,028                                                  | $(1,994,025)                                            | $(3,197,662)                                                  |
| Net Income/Loss Attributable to Common                            Stockholders          | $3,510,322                                                              | $2,141,364                                                        | $1,088,028                                                  | $(1,994,025)                                            | $(3,451,580)                                                  |
| Net Income/Loss Attributable to Common Stockholder Per                            Share | $           0.06 | $          0.04 | $         0.02 | $        (0.05) | $         (0.29) |

 

 

 

44

 

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Year            Ended December 31,5,6

 

|                               | **2007**                                                                           | **2006**                                                                           | **2005**                                                                                 | **2004**                                                                                             | **2003**               |
|------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------------|------------------------|
| **Balance Sheet Data:**            |                                                                               |                                                                               |                                                                                     |                                                                                                 |                   |
| Working Capital Surplus

(Deficit) | $ 2,473,4767                                                                  | $872,507                                                                           | $(1,334,744)                                                                             | $(6,753,721)                                                                                         | $(10,822,717)          |
| Oil and Gas Properties, Net        | $13,209,601                                                                        | $12,703,629                                                                        | $ 9,675,977                                                                              | $   12,826,903                                                                        | $12,989,443            |
| Pipeline Facilities, Net           | $12,916,667                                                                        | $13,460,667                                                                        | $13,994,453                                                                              | $   14,602,639                                                                        | $15,139,789            |
| Total Assets                       | $34,281,549                                                                        | $28,454,338                                                                        | $25,908,616                                                                              | $   28,209,749                                                                        | $30,604,240            |
| Long-Term Debt                     | $  4,315,773                                                             | $  2,730,534                                                             | $    117,912                                                              | $     1,940,890                                                             | $  6,256,818 |
| Redeemable

Preferred Stock        | $             -0- | $             -0- | $              -0- | $                -0- | $  -0-       |
| Stockholders Equity                | $28,102,871                                                                        | $24,420,205                                                                        | $ 21,961,454                                                                        | $18,349,687                                                                                          | $11,251,871            |

             

             

| **ITEM 7.** | **MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL                            CONDITION AND RESULTS OF                            OPERATIONS**             |
|-------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Results of Operations**

 

The            Company incurred a net income to holders of common stock of $3,510,322 or $0.06 per            share in 2007 compared to a net income of $2,141,364 or $0.04 per share in 2006 and            compared to a net income of $1,088,028 or $0.02 per share in 2005. The Company            recognized a tax benefit for net operating loss carry forwards in the amount of            $2,100,000 in 2007.

 

The            Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and            compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to            an increase in oil prices in Kansas; prices averaged $66.42 in 2007 and 60.84 in 2006.            Gross oil production in 2007 was just slightly less than 2006 resulting from the loss            of production in January 2007 due to the electricity outage during an ice storm. As a            result of that storm, many counties in Kansas, including some counties where the            Company has wells, lost power for the entire month of January. Producing wells in            those counties were unable to produce without electricity to run the well pumps during            the power outage.  Consequently in January 2007 the Company saw production and            revenue decline from monthly levels in late 2006. None of the Company’s            producing wells were physically damaged by the ice storm or by non

_________________________

| 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.

7                       The Company’s working            capital surplus of 2,473.476 was attributable to high commodity prices as well as an            increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the            Ten Well Program. The Company has expended approximately $1.5 million of these funds            subsequent to year-end on the Methane Project and completing the Ten Well            Program.

-

 

45

 

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production during the absence of power, but the storm did substantially            adversely impact production levels and sales in the first two months of 2007 while            at the same time causing an increase in expenses.  Eventually new poles and lines            were rebuilt on a locally massive scale and electrical power was restored, and the            Company experienced a rebound of production commencing in March 2007.

 

In            2007 the Company produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006,            a decrease of 1,244 barrels for the year. Additionally, the wells in the Eight Well            Program (former Series “A”) reached the reversionary “flip            point” in April 2007. This is the point at which the Company started receiving            85% of the participant’s interest plus our original interest of (19.3%) for an            approximate total net interest to the Company equal to an 88% interest. In 2007 those            wells produced 22,195 gross barrels of oil; the wells in the Twelve Well Program            (former Series “B”) now converted to a six well program produced 15,864            gross barrels; wells polymered produced 19,502 barrels; and, the two new wells drilled            produced 2,566 gross barrels in 2007. During 2007 the Company drilled 9 of the 10 wells            in the Ten Well Program and produced 3,649 barrels from the 5 wells that were            completed by year-end. The other three wells that were drilled in 2007 were then            completed in 2008. In March 2008, the tenth and final well in the Ten Well Program was            both drilled and completed as a producer. As of the date of this report, nine of            ten wells drilled in the Ten Well Program have been completed as producers and are            producing approximately 106 barrels per day. During the first half of 2008 the Company            expects the reversionary flip point for the Twelve Well Program (former Series            “B”) now converted to a six well program, to be achieved.

 

Gas            prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in            2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of            oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel            in 2006, and. $53.90 per barrel in 2005.

 

Production costs and taxes in 2007 increased to $4,322,833 from            $3,287,233 in 2006 and $3,046,460 in 2005. The difference is due to increased            work-overs to increase production, increased taxes, and overall cost increases of            supplies in the industry.

 

Depletion, depreciation, and amortization for 2007 was $1,631,468, a            decrease from $1,911,416 in 2006 due to production volumes added to future reserves            from drilling activities. Depletion, depreciation, and amortization increased to            $1,911,416 in 2006 from $1,605,043 in 2005. The increase in 2006 was due to a change in            focus by the Company toward drilling in Kansas rather than in Tennessee, therefore            removing drilling and development locations in Tennessee.

 

The            Company’s general and administrative costs of $1,417,001 in 2007 remained            generally consistent with 2006 levels of $1,293,109 and 2005 levels of $1,322,616. The            2007, 2006 and 2005 costs included non-cash charges related to stock options of            $116,476, $159,160 and $103,400 respectively.

 

46

 

----

The increase in interest expense in 2007 relates to the borrowing            base increase of the Citibank credit facility in 2007. Interest expense for 2006            decreased significantly over 2005 levels. This was due to the conversion of the            Company’s preferred stock, which was subject to mandatory redemption, into either            interest in a drilling program, common stock or cash payoffs. As of December 31, 2006,            the Company’s only debt financing were vehicle loans totaling $195,801 and the            CitiBank loan of $2,600,000.

The Company’s public relations costs remained stable at $21,605            for 2007, compared to $26,037 for 2006 and $30,020 for 2005 as the Company continued to            apply cost saving methods in the preparation of its annual report and in publishing of            press releases.

Professional fees in 2007 were $232,197 compared to $173,932 in 2006.            This was due to the Company commencing its review of its internal controls over its            financial reporting in accordance with Item 308(T) of Regulation S-K. Professional fees            in 2006 decreased from 2005 levels as the Company’s litigation was            settled.

 

The            Company recorded a deferred tax asset of $2,100,000 in 2007 relating to the            Company’s net operating loss carry forwards. The Company recorded a gain on            disposal of preferred stock of $655,746 in 2005.

 

**Liquidity and Capital Resources**

 

On            June 29, 2006, the Company closed a $50,000,000 revolving senior credit facility            between the Company and Citibank Texas, N.A. in its own capacity and also as agent for            other banks.  Under the facility, loans and letters of credit were available to            the Company on a revolving basis in an amount outstanding not to exceed the lesser of            $50,000,000 or the borrowing base in effect from time to time. The Company’s            initial borrowing base was set at $2,600,000.  The initial loan under the facility            with Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing            interest at a floating rate equal to LIBOR plus 2.5%, resulting in interest of            approximately 8.2%.  Interest only was payable during the term of the loan and the            principal balance of the loan is due thirty-six months from closing.   The            facility is secured by a lien on substantially all of the Company’s producing and            non-producing oil and gas properties and pipeline assets.

 

The            Company used $1.393 million of the proceeds of the $2.6 million loan from Citibank to            exercise the Company’s option to repurchase from Hoactzin Partners, L.P.            (“Hoactzin”), the Company’s obligation to drill for Hoactzin the            final six wells of the Company’s Twelve Well Program. Peter E. Salas, the            Chairman of the Board of Directors of the Company, is the controlling person of            Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management,            Inc., the general partner of Dolphin Offshore Partners, L.P., which is the            Company’s largest shareholder. A detailed description of the Twelve Well Program            is set forth In “Item 1 – Business” under the subheading            “Kansas Drilling Programs”.

If            the Company had not exercised its repurchase option, Hoactzin would have

 

47

 

----

received a 94% working interest in the final six wells of the Twelve            Well Program until payout as established under the terms of the Twelve Well            Program.  However, as a result of the terms of the repurchase option, Hoactzin            will receive only a 6.25% overriding royalty in the next six Company wells to be            drilled, plus an additional 6.25% overriding royalty in the six Program Wells that have            previously been drilled.  As a further result of the repurchase, the Twelve Well            Program was converted into a six well program, and because six wells had been drilled            by the Company as of June 30, 2006 the drilling obligation in this program was            satisfied upon exercise of the repurchase option.  Consequently, as of June 30,            2006, all well-drilling obligations of the Company owed to participants have been            satisfied as to the Twelve Well Program (offered to Hoactzin and converted to a 6-well            program upon the Company’s repurchase of the obligation to drill the last six            wells as described above) as well as the Company’s earlier Eight Well Program            (offered to the former Series A preferred stockholders). 

 

Under the terms of the Eight Well Program and Twelve (now Six) Well            program, upon payment to the participants of 80% of the value invested in the Program            from proceeds from production, the participants will pay the Company a management fee            of 85% of their proceeds. As to the Eight Well Program, that point was reached in April            2007 resulting in an increase in revenues from these wells to the Company of            approximately $50,000 per month at current volumes and prices. As to the Twelve (now 6)            Well Program, that point is expected to be reached during the first half of 2008. It is            anticipated, based upon current volumes and prices that this will result in an increase            in revenues to the Company of approximately $50,000 per month.

 

On            April 19, 2007 the Company borrowed an additional $700,000 from Citibank under the            existing Citibank revolving credit facility. The additional borrowing resulted            from Citibank’s increase in the Company’s borrowing base under the credit            facility from $2.6 million to $3.3 million as a result of Citibank’s periodic            borrowing base review conducted under the terms of credit facility.  With the            additional borrowing, the Company had borrowed the full amount of the $3.3 million            borrowing base which was available to it under the Citibank revolving credit facility.            Repayment of this additional sum was subject to the terms and conditions of the            Citibank credit facility. The additional amount borrowed was used for additional            development of the Company’s producing properties.

 

On            December 17, 2007, Citibank assigned the Company’s revolving credit facility with            Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by            the Company.

 

Under            the facility as assigned to Sovereign, loans and letters of credit will be available to            the Company on a revolving basis in an amount outstanding not to exceed the lesser of            $20 million or the Company’s borrowing base in effect from time to time. The            Company’s initial borrowing base with Sovereign was set at $7.0 million, an            increase from its borrowing base of $3.3 million with Citibank prior to the            assignment.

 

The            Company’s initial borrowing on December 17, 2007 under its new facility with            Sovereign was approximately $4.2 million which will bear interest at a floating rate            equal to prime as published in the Wall Street Journal plus 0.25% resulting in a            current interest rate of

 

48

 

----

approximately 7.5%. Interest only is payable during the term of the loan            and the principal balance of the loan is due December 31, 2010. The Sovereign facility            is secured by substantially all of the Company’s producing and non-producing oil            and gas properties and pipeline and the Company’s Methane Project            assets.

 

The            Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds            it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign            was used to pay bank fees and attorney fees relating to the assignment in the amount of            approximately $75,000 and the balance of approximately $825,000 was used to pay a            portion of the purchase price for equipment to be utilized in the Methane Project            currently under construction in Church Hill, Tennessee by MMC, the Company’s            wholly-owned subsidiary. See, “Item 1 - Business” under the subheading            “The Methane Project”.

 

Net            cash provided by operating activities for 2007 was $3,446,677 compared to net cash            provided by operating activities of $4,353,966 in 2006. The Company’s net income            in 2007 increased to $3,510,322 from $2,141,364 in 2006. The impact on cash provided by            operating activities was due to the net income for 2007 and was increased by non-cash            depletion, depreciation, and amortization of $1,631,468 and by non-cash compensation            and services paid by insurance of equity instruments of $116,476. Cash flow provided in            working capital items in 2007 was $211,742 compared to cash provided by working capital            items of $122,152 in 2006. The Company’s net income for 2007 included a non-cash            deferred tax asset for net operating loss carry forwards of $2,100,000.

 

Net            cash provided by operating activities for 2006 was $4,353,966 compared to net cash            provided by operating activities of $2,113,763 in 2005. The Company’s net income            in 2006 increased to $2,141,364 from $1,088,028 in 2005. The impact on cash provided by            operating activities was due to the net income for 2006 and was increased by non-cash            depletion, depreciation, and amortization of $1,911,416 and by non-cash compensation            and services paid by insurance of equity instruments of $159,160. Cash flow provided in            working capital items in 2006 was $122,152 compared to cash used in working capital            items of $209,601 in 2005. This resulted in 2006 from decreases from 2005 in accounts            receivable of $434,565 offset by a decrease in other accrued liabilities of            $251,327.

 

Net            cash used in investing activities amounted to $3,145,764 for 2007 compared to net cash            used in investment activities in the amount of $4,413,185 for 2006. The decrease in net            cash used in investing activities during 2006 was primarily attributable to an increase            in oil and gas properties of $5,190,611 offset by drilling program funds received of            $3,850,000 and an increase in additions to methane project of $1,649,710.

 

Net            cash used in investing activities amounted to $4,413,185 for 2006 compared to net cash            provided by investment activities in the amount of $2,166,854 for 2005. The increase in            net cash used in investing activities during 2006 was primarily attributable to an            increase in oil and gas properties of $5,239,862 offset by a decreased drilling program            portion of additional drilling costs of $1,067,400.

 

49

 

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Net            cash provided by financing activities increased to $1,556,261 in 2007 from cash            provided by financing activities of $167,915 in 2006. In 2007 the primary sources of            financing included proceeds from borrowings of $1,687,236 compared to $2,732,145 in            2006. The primary use of cash in financing activities in 2006 was to repay the drilling            program liability of $2,324,400.

 

Net            cash provided by financing activities increased to $167,915 in 2006 from cash used in            financing activities of $4,287,383 in 2005. In 2006 the primary sources of financing            included proceeds from borrowings of $2,732,145 compared to $155,075 in 2005. The            primary use of cash in financing activities in 2006 was to repay the drilling program            liability of $2,324,400.

 

**Critical Accounting Policies**

 

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

 

| **Revenue                            Recognition** |   |
|----------------------------------------------------|--------|

 

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

 

| **Full Cost Method of                            Accounting** |   |
|---------------------------------------------------------------|--------|

 

The            Company follows the full cost method of accounting for oil and gas property            acquisition, exploration and development activities. Under this method, all productive            and non-productive costs incurred in connection with the acquisition of, exploration            for and development of oil and gas reserves for each cost center are capitalized.            Capitalized costs include lease acquisitions, geological and geophysical work, day rate            rentals and the costs of drilling, completing and equipping oil and gas wells. Costs,            however, associated with production and general corporate activities are expensed in            the period incurred. Interest costs related to unproved properties and properties under            development are also capitalized to oil and gas properties. Gains or losses are            recognized only upon sales or dispositions of significant amounts of oil and            gas

 

50

 

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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 2007, 2006 or            2005.

 

|   |  |
|--------|--|

|   |   |
|--------|--------|

**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 of December 31, 2007 were determined by            LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on            production, and timing of development expenditures includes many factors beyond the            Company’s control. The future estimates of net cash flows from the            Company’s proved reserves and their present value are based upon various            assumptions about future production levels, prices, and costs that may prove to be            incorrect over time. Any significant variance from assumptions could result in the            actual future net cash flows being materially different from the            estimates.          

 

| **Asset Retirement                            Obligations** |   |
|-------------------------------------------------------------|--------|

 

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

 

**Recent Accounting Pronouncements**

 

In            July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in            Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the            accounting for uncertainty in tax positions taken or expected to be taken in a            tax

 

51

 

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return, including issues relating to financial statement recognition and            measurement. FIN 48 provides that the tax effects from an uncertain tax position can be            recognized in the financial statements only if the position is "more-likely-than-not"            to be sustained if the position were to be challenged by a taxing authority. The            assessment of the tax position is based solely on the technical merits of the position,            without regard to the likelihood that the tax position may be challenged. If an            uncertain tax position meets the "more-likely-than-not" threshold, the largest amount            of tax benefit that is more than 50 percent likely to be recognized upon ultimate            settlement with the taxing authority, is recorded. The provisions of FIN 48 are            effective for fiscal years beginning after December 15, 2006, with the cumulative            effect of the change in accounting principle recorded as an adjustment to opening            retained earnings. Consistent with the requirements of FIN 48, the Company adopted FIN            48 on January 1, 2007. The Company does not expect the interpretation will have an            impact on its results of operations or financial position.

 

In            September 2006, the Securities and Exchange Commission staff published Staff            Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of            Prior Year Misstatements when Quantifying Misstatements in Current Year Financial            Statements." SAB 108 addresses quantifying the financial statement effects of            misstatements, specifically, how the effects of prior year uncorrected errors must be            considered in quantifying misstatements in the current year financial statements. SAB            108 is effective for fiscal years ending after November 15, 2006. The Company adopted            SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the            Company’s consolidated financial statements.

 

In            September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard            provides guidance for using fair value to measure assets and liabilities. It defines            fair value, establishes a framework for measuring fair value under generally accepted            accounting principles and expands disclosures about fair value measurement. Under the            standard, fair value refers to the price that would be received to sell an asset or            paid to transfer a liability in an orderly transaction between market participants in            the market in which the reporting entity transacts. It clarifies the principle that            fair value should be based on the assumptions market participants would use when            pricing the asset or liability. In support of this principle, the standard establishes            a fair value hierarchy that prioritizes the information used to develop those            assumptions. Under the standard, fair value measurements would be separately disclosed            by level within the fair value hierarchy. Statement 157 is effective for financial            statements issued for fiscal years beginning after November 15, 2007. The Company            continues to evaluate the impact the adoption of this statement could have on its            financial condition, results of operations and cash flows.

 

In            February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial            Assets and Financial Liabilities — As amended” (“SFAS 159”).            SFAS 159 permits entities to elect to report eligible financial instruments at fair            value subject to conditions stated in the pronouncement including adoption of SFAS 157            discussed above. The purpose of SFAS 159 is to improve financial reporting by            mitigating volatility in earnings related to current reporting requirements. The            Company is considering the applicability of SFAS 159 and will determine if

 

52

 

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adoption is appropriate. The effective date for SFAS 159 is for fiscal            years beginning after November 15, 2007.

 

 

**CONTRACTUAL OBLIGATIONS**

 

The following table summarizes the Company’s contractual            obligations at December 31, 2007:

 

 

Payments Due By Period

 

| Contractual Obligations      | Total      | Less than

1year | 1-3

years | 3-5

years | More than

5 years |
|------------------------------|------------|------------------|------------|------------|--------------------|
| Long-Term Debt Obligations8  | $4,373,660 | 57,887           | $4,315,773 | $-0-       | $-0-               |
| Capital Lease Obligations    | $-0-       | $-0-             | $-0-       | $-0-       | $-0-               |
| Operating Lease Obligations9 | $31,673    | $31,673          | $-0-       | $-0-       | $-0-               |
| Purchase Obligations         | $-0-       | $-0-             | $-0-       | $-0-       | $-0-               |
| Other Long-Term Liabilities  | $-0-       | $-0-             | $-0-       | $-0-       | $-0-               |
| Total                        | $4,405,333 | $89,560          | $4,315,773 | $-0-       | $-0-               |

 

             

| **ITEM 7A.** | **QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET                            RISKS**                  |
|--------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

**Commodity Risk**

 

The Company's major market risk exposure is in the pricing applicable to            its oil and gas production. Realized pricing is primarily driven by the prevailing            worldwide price for 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 $49.05 per barrel to a high of $89.18 per barrel            during 2007. Gas price realizations ranged from a monthly low of $5.43 per Mcf to a            monthly high of $7.59 per Mcf during the same period. The Company did not enter into            any hedging agreements in 2007 to limit exposure to oil and gas price            fluctuations.

_________________________

| 8 

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

| 9 

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

 

 

53

 

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**Interest Rate Risk**

 

At            December 31, 2007, the Company had debt outstanding of approximately $4,373,660            including, as of that date, $4,200,000 owed on its credit facility with Citibank Texas,            N. A., which was assigned on December 17, 2007 to Sovereign Bank. The interest rate on            the credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s            remaining debt of $173,660 has fixed interest rates ranging from 5.5% to 8.25%. As a            result, the Company's annual interest costs in 2007 fluctuated based on short-term            interest rates on approximately 96% of its total debt outstanding at December 31, 2007.            The impact on interest expense and the Company’s cash flows of a 10 percent            increase in the interest rate on the Sovereign Bank credit facility would be            approximately $29,400, assuming borrowed amounts under the credit facility remained at            the same amount owed as of December 31, 2007. The Company did not have any open            derivative contracts relating to interest rates at December 31, 2007.

 

**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** |
|-------------|------------------------------------------------------------------------------|

 

None.

 

54

 

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| **ITEM 9A (T).** | **CONTROLS AND PROCEDURES** |
|------------------|-----------------------------|

 

**Evaluation of Disclosure Controls and            Procedures**

 

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

 

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

 

**Management’s Report on Internal Control over Financial            Reporting**

 

Management of the Company is responsible for establishing and            maintaining adequate internal control over financial reporting, as such term is defined            in the Securities Exchange Act of 1934 Rule 13a-15(f). Internal control over financial            reporting refers to the process designed by, or under the supervision of, the            Company’s Chief Executive Officer and Chief Financial Officer, and effected by            the Company’s Board of Directors, management and other personnel, to provide            reasonable assurance regarding the reliability of financial reporting and the            preparation of financial statements for external purposes in accordance with generally            accepted accounting principles, and includes those policies and procedures            that:

             

|   | **•** | Pertain to the maintenance of records that, in                            reasonable detail, accurately and fairly reflect the transactions and                            dispositions of the Company’s assets; |
|--------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

|   | **•** | Provide reasonable assurance that transactions are                            recorded as necessary to permit preparation of financial statements in                            accordance with generally accepted accounting principles, and that                            receipts and expenditures are being made only in accordance with                            authorizations of the Company’s management and directors;                            and |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

55

 

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|   | **•** | Provide reasonable assurance regarding prevention or                            timely detection of unauthorized acquisition, use or disposition of the                            Company’s assets that could have a material effect on the                            Company’s financial statements. |
|--------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

Under the supervision and with the participation of the Company’s            management, including the Chief Executive Officer and the Chief Financial Officer, the            Company’s management conducted an evaluation of the effectiveness of the            Company’s internal control over financial reporting as of December 31, 2007 as            required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this            assessment, the Company’s management used the criteria set forth in the framework            in “Internal Control – Integrated Framework” issued by the Committee            of Sponsoring organizations of the Treadway Commission (“COSO”). Based on            the evaluation conducted under the framework in “Internal Control –            Integrated Framework,” issued by COSO the Company’s management concluded            that the Company’s internal control over financial reporting was effective as of            December 31, 2007.

 

This            report does not include an attestation report of the Company’s registered public            accounting firm regarding internal control over financial reporting. Management’s            report was not subject to attestation by the Company’s registered public            accounting firm pursuant to temporary rules of the SEC that permit the Company to            provide only management’s report in this Annual Report on Form 10-K.

 

Because of its inherent limitations, internal control over financial            reporting may not prevent or detect misstatements. Also, projections of any evaluation            of effectiveness into future periods are subject to the risk that controls may become            inadequate because of changes in conditions, or that the degree of compliance with the            policies or procedures may deteriorate.

             

**Changes in Internal Controls**

 

There have been no changes to the Company’s system of internal            control over financial reporting during the year ended December 31, 2007 that has            materially affected, or is reasonably likely to materially affect, the Company’s            system of controls over financial reporting.

 

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

 

| **ITEM 9B.** | **OTHER INFORMATION** |
|--------------|-----------------------|

 

The            Company’s 2008 Annual Meeting of Stockholders will be held on June 2, 2008 at            9:00 a.m. at the Homewood Suites by Hilton, 10935 Turkey Drive, Knoxville, Tennessee            37922. Proposals of stockholders sought to be presented at the 2008 annual meeting must            be received in writing, by the Chief Executive Officer of the Company at the            Company’s offices by

 

56

 

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the            close of business on April 4, 2008 in order to be considered for inclusion in the            Company's proxy statement relating to that meeting.

 

58

 

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**PART III**

 

Certain information required by Part III of this Report is incorporated            by reference from the Company’s definitive proxy statement to be filed with the            SEC in connection with the solicitation of proxies for the Company’s 2008 Annual            Meeting of Stockholders (the “Proxy Statement”).

 

| **ITEM 10.** | **DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE                            GOVERNANCE** |
|--------------|------------------------------------------------------------------------------------------|

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

 

The            information required by this Item with respect to corporate governance regarding the            Nominating Committee and Audit Committee of the Board of Directors is incorporated by            reference from the section entitled “Board of Directors - Committees” in            the Proxy Statement.

 

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

 

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

 

| **ITEM 11.**

****EXECUTIVE                            COMPENSATION**** |   |
|-------------------------------------------------------------------------|--------|

 

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

 

| **ITEM 12.** | **SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND                            MANAGEMENT AND RELATED STOCKHOLDER MATTERS** |
|--------------|-------------------------------------------------------------------------------------------------------------------------------|

 

Except as set forth below, the information required by this Item            regarding security ownership of certain beneficial owners and directors and officers is            incorporated by reference

 

59

 

----

from            the sections entitled “Voting Securities and Principal Holders” and            “Beneficial Ownership of Directors and Officers” in the Proxy            Statement.

 

**Equity Compensation Plan Information**

 

The            following table sets forth information regarding the Company’s equity            compensation plans as of December 31, 2007.

 

 

| 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 holders       |  

                             

                             

2,441,000                                                                                                                                                            |  

                             

                             

$0.30                                                                                                                                                                                    |  

                             

                             

39,368                                                                                                      |
| Equity compensation

plans not approved

by security holders10 |  

                             

                             

0                                                                                                                                                                    |  

                             

                             

n/a                                                                                                                                                                                      |  

                             

                             

0                                                                                                           |
| Total                                                          | 2,441,000                                                                                                                                                                                                                                            | $0.30                                                                                                                                                                                                                                                                    | 39,638                                                                                                                                                                                      |

 

_________________________

10                      Refers to Tengasco, Inc. Stock            Incentive Plan (the “Plan”) which was adopted to provide an incentive to            key employees, officers, directors and consultants of the Company and its present and            future subsidiary corporations, and to offer an additional inducement in obtaining the            services of such individuals. The Plan provides for the grant to employees of the            Company of "Incentive Stock Options," within the meaning of Section 422 of the Internal            Revenue Code of 1986, as amended, Nonqualified Stock Options to outside Directors and            consultants to the Company and stock appreciation rights. The plan was approved by the            Company’s shareholders on June 26, 2001. Initially, the Plan provided for the            issuance of a maximum of 1,000,000 shares of the Company's $.001 par value common            stock. Thereafter, the Company’s Board of Directors adopted and the shareholders            approved an amendment to the Plan to increase the aggregate number of shares that may            be issued under the Plan from 1,000,000 shares to 3,500,000 shares. On February 1,            2008, the Company’s Board of Directors adopted further amendments to the Plan to            increase the number of shares that may be issued under the Plan by 3,500,000 shares and            to extend the Plan for another 10 years from October 24, 2010 to October 24, 2020. The            Company’s shareholders will be requested to vote to approve these amendments at            the upcoming Annual Meeting of the Company’s shareholders to be held on June 2,            2008.

 

60

 

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| **ITEM 13.** | **CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND                            DIRECTOR INDEPENDENCE** |
|--------------|----------------------------------------------------------------------------------------------------------|

 

The            information required by this Item as to transactions between the Company and related            persons is incorporated by reference from the section entitled “Certain            Transactions” in the Proxy Statement.

The            information required by this Item as to the independence of the Company’s            directors and members of the committees of the Company’s Board of Directors is            incorporated by reference from the section entitled “Board of Directors”            and the subsections thereunder entitled “Director Independence” and            “Committees” set forth in “Proposal No. 1: Election of            Directors” in the Proxy Statement.

             

| **ITEM 14.** | **PRINCIPAL ACCOUNTANTS FEES AND                            SERVICES** |
|--------------|------------------------------------------------------------------------|

 

**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 Income Statements |
|--------|--------------------------------|

|   | 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.

 

61

 

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|   | Exhibit Index |
|--------|---------------|

 

| Exhibit Number | Description                                                                                                                                                                                                                                                                                                                                                                                                   |
|----------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1            | Charter (Incorporated by reference to Exhibit 3.7 to the                            registrant’s registration statement on Form 10-SB filed August 7,                            1997 (the “Form 10-SB”))                                                                                                                                                                                   |
| 3.2            | Articles of Merger and Plan of Merger (taking into                            account the formation of the Tennessee wholly-owned subsidiary for the                            purpose of changing the Company’s domicile and effecting reverse                            split) (Incorporated by reference to Exhibit 3.8 to the Form                            10-SB)                              |
| 3.3            | Articles of Amendment to the Charter dated June 24, 1998                            (Incorporated by reference to Exhibit 3.9 to the registrant’s                            annual report on Form 10-KSB filed April 15, 1999 (the “1998 Form                            10-KSB”))                                                                                                         |
| 3.4            | Articles of Amendment to the Charter dated October 30,                            1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form                            10-KSB)                                                                                                                                                                                                                         |
| 3.5            | Articles of Amendment to the Charter filed March 17,                            2000 (Incorporated by reference to Exhibit 3.11 to the                            registrant’s annual report on Form 10-KSB filed April 14, 2000                            (the “1999 Form 10-KSB”))                                                                                                       |
| 3.6            | By-laws (Incorporated by reference to Exhibit 3.2 to the                            Form 10-SB)                                                                                                                                                                                                                                                                                                               |
| 3.7            | Amendment and Restated By-laws dated May 19, 2005                            (Incorporated by reference to the registrant’s annual report on                            Form 10-K for the year ended December 31, 2005)                                                                                                                                                                                 |
| 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           | 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)                                                                                                                                                                                      |
| 10.5           | 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)        |
| 10.6           | Promissory Note made by Tengasco, Inc. and Tengasco                            Pipeline Corporation to Dolphin Offshore Partners, LP dated December                            30, 2004 in the principal amount of $550,000 (Incorporated by reference                            from to Exhibit 10.19 to the registrant’s Annual Report on Form                            10-K filed March 31, 2005) |
| 10.7           | 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”)                                                                     |
| 10.8           | 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)                                                                                                                                                                                                   |

 

 

62

 

----

 

| 10.9                                      | Amended and Restated Promissory Note made by Tengasco,                            Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP                            dated May 19, 2005 in the principal amount of $700,000 ((Incorporated                            by reference to Exhibit 10.1 to the registrant’s current report                            on Form 8-K dated May 23, 2005)                                                      |
|-------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.10                                     | Amendment to the Tengasco, Inc. Stock Incentive Plan                            dated May 19, 2005 (Incorporated by reference to Exhibit 4.2 to the                            registrant’s registration statement on Form S-8 filed June 3,                            2005)                                                                                                                                                                                         |
| 10.11                                     | Promissory Note made by Tengasco, Inc. and Tengasco                            Pipeline Corporation to Dolphin Offshore Partners, LP dated August 22,                            2005 in the principal amount of $1,814,000 (Incorporated by reference                            to Exhibit 10.1 to the registrant’s current report on Form 8-K                            dated August 22, 2005 (the “August 22, 2005                            8-K”)) |
| 10.12                                     | Amended and Restated Promissory Note made by Tengasco,                            Inc. and Tengasco Pipeline Corporation dated August 18, 2005 in the                            principal amount of $700,000 (Incorporated by reference to Exhibit 10.2                            to the August 22, 2005 8-K.)                                                                                                                                                            |
| 10.13                                     | Subscription Agreement of Hoactzin Partners, L.P. for a                            94.275% working interest in the Company’s twelve well drilling                            program on its Kansas Properties. (Incorporated by reference to Exhibit                            10.1 to the registrant’s current report on Form 8-K dated October                            5, 2005)                                                                           |
| 10.14                                     | Loan and Security Agreement dated as of June 29, 2006                            between Tengasco, Inc. and Citibank Texas, N.A. (Incorporated by                            reference to Exhibit 10.1 to the registrant’s current report on                            Form 8-K dated June 29, 2006)                                                                                                                                                                 |
| 10.15*                                    | Subscription Agreement of Hoactzin Partners, L.P. for                            the Company’s ten well drilling program on its Kansas Properties                            dated August 3, 2007.                                                                                                                                                                                                                                                                    |
| 10.16*                                    | Agreement and Conveyance of Net Profits Interest dated                            September 17, 2007 between Manufactured Methane Corporation as Grantor                            and Hoactzin Partners, LP as Grantee.                                                                                                                                                                                                                                                   |
| 10.17*                                    | Agreement for Conditional Option for Exchange of Net                            Profits Interest for Convertible Preferred Stock dated September 17,                            2007 between Tengasco, Inc., as Grantor and Hoactzin Partners, L.P., as                            Grantee.                                                                                                                                                                                 |
| 10.18*                                    | Assignment of Notes and Liens Dated December 17, 2007                            between Citibank, N.A., as Assignor, Sovereign Bank, as Assignee and                            Tengasco, Inc., Tengasco Land & Mineral Corporation and Tengasco                            Pipeline Corporation as Debtors                                                                                                                                                            |
| 10.19                                     | Employment Agreement dated December 18, 2007 between                            Tengasco, Inc. and Charles Patrick McInturff (Incorporated by reference                            to Exhibit 10.1 to the registrant’s current report on Form 8-K                            dated December 18, 2007)                                                                                                                                                                 |
| 10.20*                                    | Management Agreement dated December 18, 2007 between                            Tengasco, Inc. and Hoactzin Partners, L.P.                                                                                                                                                                                                                                                                                                                                                  |
| 14                                        | Code of Ethics (Incorporated by reference to Exhibit 14                            to the registrant’s annual report on Form 10-K filed March 30,                            2004)                                                                                                                                                                                                                                                                                    |
| 17.1                                      | Letter of resignation of Clarke H. Bailey as a Director                            of the Company dated March 27, 2007 (Incorporated by reference to                            Exhibit 17.1 to the registrant’s current report on Form 8-K dated                            March 27, 2007)                                                                                                                                                                          |
| 21*                                       | List of subsidiaries                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| 23.1*                                     | Consent of LaRoche Petroleum Consultants,                            Ltd.                                                                                                                                                                                                                                                                                                                                                                                                   |
| 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                                                                                                                                                                                                                                                                     |

 

 

63

 

----

 

|   | * Exhibit filed with this Report |
|--------|----------------------------------|

 

 

64

 

----

|   | **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, 2008

|   | TENGASCO, INC. |
|--------|----------------|

|   | (Registrant) |
|--------|--------------|

 

|   | By:s/Jeffrey R.                            Bailey |
|--------|---------------------------------------------------|

|   | Jeffrey R. Bailey, |
|--------|--------------------|

|   | Chief Executive Officer |
|--------|-------------------------|

 

|   | By:s/Mark A.                            Ruth |
|--------|----------------------------------------------|

|   | Mark A. Ruth, |
|--------|---------------|

|   | Principal Financial and Accounting Officer |
|--------|--------------------------------------------|

 

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

 

| **Signature**                                                                | **Title**                                   | **Date**        |
|------------------------------------------------------------------------------|---------------------------------------------|-----------------|
| s/Jeffrey R. Bailey

Jeffrey R. Bailey

                                | Director;

Chief Executive Officer          | March 31 , 2008 |
| s/Matthew K. Behrent

Matthew K. Behrent

                              | Director                                    | March 31, 2008  |
| s/John A. Clendening

John A. Clendening

                              | Director                                    | March 31, 2008  |
| s/Carlos P. Salas

Carlos P. Salas

                                    | Director                                    | March 31, 2008  |
| s/Peter E. Salas

Peter E. Salas

                                      | Director                                    | March 31, 2008  |
| s/Mark A. Ruth

Mark A. Ruth                                                 | Principal and Financial

Accounting Officer | March 31, 2008  |

 

 

 

 

                                                                                                                                                                         

 

 

 

 

 

 

|   | **Tengasco, Inc.** |
|--------|--------------------|

|   | **and Subsidiaries** |
|--------|----------------------|

 

 

 

 

 

**Consolidated Financial Statements**

**Years Ended December 31, 2007, 2006 and 2005**

 

 

 

 

 

 

 

----

 

| **Report of Independent Registered Public Accounting                            Firm**                   | F-3

                                                    |
|----------------------------------------------------------------------------------------------------------|---------------------------------------------------------------|
|                                                                                                     |                                                          |
| **Consolidated Financial Statements**                                                                    |                                                          |
| Consolidated Balance Sheets                                                                              | F-4 – F-5

                              |
| Consolidated Income Statements                                                                           | F-6

                                                    |
| Consolidated Statements of Stockholders’                               Equity  |  

F-7                                                   |
|                                                                                                     |                                                          |
| Consolidated Statements of Cash Flows                                                                    | F-8

                                                    |
| Notes to Consolidated Financial Statements                                                               | F-9 – F-32                                    |

 

 

 

 

----

 

REPORT            OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Board            of Directors and Stockholders

Tengasco, Inc. and Subsidiaries

Knoxville, Tennessee

 

We            have audited the accompanying consolidated balance sheets of Tengasco, Inc. and            Subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements            of operations, changes in stockholders’ equity and cash flows for each of the            three years in the period ended December 31, 2007. These consolidated financial            statements are the responsibility of the Company’s management. Our responsibility            is to express an opinion on these consolidated 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            audit 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 consolidated financial position of Tengasco, Inc. and            Subsidiaries as of December 31, 2007 and 2006 and the results of their operations and            cash flows for each of the three years in the period ended December 31, 2007 in            conformity with accounting principles generally accepted in the United States of            America.

 

/s/            Rodefer Moss & Co, PLLC

Knoxville, Tennessee

March 27, 2008

 

 

**F-3**

 

----

Tengasco, Inc. and Subsidiaries

**Consolidated Balance Sheets**

 

 

| *December 31,*                                                                                                   | **2007**                                          | **2006**                                        |
|------------------------------------------------------------------------------------------------------------------|---------------------------------------------------|-------------------------------------------------|
|                                                                                                             |                                              |                                            |
| **Assets**                                                                                                       |                                              |                                            |
|                                                                                                             |                                              |                                            |
|                                                                                                             |                                              |                                            |
| **Current**                                                                                                      |                                              |                                            |
| Cash and cash equivalents                                                                                        | **$**    **2,226,839**        | $      369,665    |
| Accounts receivable                                                                                              | **1,057,148**                                     | 719,840                                         |
| Participant receivables                                                                                          | **49,872**                                        | 13,008                                          |
| Inventory                                                                                                        | **460,365**                                       | 550,522                                         |
| Other current assets                                                                                             | **11,056**                                        | 11,056                                          |
|                                                                                                             |                                              |                                            |
| **Total current assets**                                                                                         | **3,805,280**                                     | 1,664,091                                       |
|                                                                                                             |                                              |                                            |
| Restricted cash                                                                                                  | **120,500**                                       | 120,500                                         |
| Loan fees                                                                                                        | **223,733**                                       | 237,738                                         |
|                                                                                                             |                                              |                                            |
| **Oil and gas properties,**net                            (on the basis

of full cost accounting)                | **13,209,601**                                    | 12,703,629                                      |
|                                                                                                             |                                              |                                            |
| **Pipeline facilities,**net of                            accumulated

depreciation of $3,423,099 and $2,879,099 | **12,916,667**                                    | 13,460,667                                      |
|                                                                                                             |                                              |                                            |
| **Other property and                            equipment**, net                                                 | **256,058**                                       | 267,713                                         |
| Deferred Tax Asset                                                                                               | **2,100,000**                                     | -                                               |
| Methane Project                                                                                                  | **1,649,710**                                     | -                                               |
|                                                                                                             |                                              |                                            |
|                                                                                                             |                                              |                                            |
|                                                                                                             | **$**     **34,281,549** | $      28,454,338 |
|                                                                                                             |                                              |                                            |

 

*See accompanying Notes to Consolidated Financial            Statements*

 

 

**F-4**

 

----

Tengasco, Inc. and Subsidiaries

**Consolidated Balance Sheets**

 

 

| *December 31,*                                                                                 | **2007**                                                | **2006**                                          |
|------------------------------------------------------------------------------------------------|---------------------------------------------------------|---------------------------------------------------|
|                                                                                           |                                                    |                                              |
| **Liabilities and Stockholders’                            Equity**                      |                                                    |                                              |
|                                                                                           |                                                    |                                              |
| **Current liabilities**                                                                        |                                                    |                                              |
| Current maturities of long                            term debt                                | **$**      **57,887**     | $       65,267 |
| Accounts payable                                                                               | **903,238**                                             | 687,475                                           |
| Accrued interest payable                                                                       | **  10,005**                                  | 8,432                                             |
| Other accrued liabilities                                                                      | **  360,674**                                 | 30,410                                            |
|                                                                                           |                                                    |                                              |
| **Total current liabilities**                                                                  | **1,331,804**                                           | 791,584                                           |
|                                                                                           |                                                    |                                              |
| **Asset retirement obligations**                                                               | **531,101**                                             | 512,015                                           |
|                                                                                           |                                                    |                                              |
| **Long term debt,**less                            currentmaturities                           | **4,315,773**                                           | 2,730,534                                         |
|                                                                                           |                                                    |                                              |
| **Total liabilities**                                                                          | **6,178,678**                                           | 4,034,133                                         |
|                                                                                           |                                                    |                                              |
|  

                                                                                  |                                                    |                                              |
| **Stockholders’ equity**                                                                 |                                                    |                                              |
| Common stock, $.001 par value; authorized 100,000,000                            shares;  |                                                    |                                              |
| 59,155,750 and 59,003,284 shares issued and                            outstanding             | **59,156**                                              | 59,004                                            |
| Additional paid-in capital                                                                     | **54,689,525**                                          | 54,517,333                                        |
| Accumulated deficit                                                                            | **(26,645,810)**                                        | (30,156,132)                                      |
|                                                                                           |                                                    |                                              |
| **Total Stockholders’ equity**                                                           | **28,102,871**                                          | 24,420,205                                        |
|                                                                                           | **$**      **34,281,549** | $      28,454,338   |
|                                                                                           |                                                    |                                              |

 

*See accompanying Notes to Consolidated Financial            Statements*

 

 

**F-5**

 

----

Tengasco, Inc. and Subsidiaries

**Consolidated Income Statements**

 

 

| *Years ended December 31,*                                                 | **2007**                                         | **2006**                                              | **2005**                                              |
|----------------------------------------------------------------------------|--------------------------------------------------|-------------------------------------------------------|-------------------------------------------------------|
|                                                                       |                                             |                                                  |                                                  |
| **Revenues and other income**                                              |                                             |                                                  |                                                  |
| Oil and gas revenues                                                       | **$**    **9,300,144**       | $     8,896,036              | $     7,076,790              |
| Pipeline transportation revenues                                           | **51,492**                                       | 87,822                                                | 94,911                                                |
| Interest Income                                                            | **16,988**                                       | 17,823                                                | 1,175                                                 |
|                                                                       |                                             |                                                  |                                                  |
| Total revenues and other income                                            | **9,368,624**                                    | 9,001,681                                             | 7,172,876                                             |
|                                                                       |                                             |                                                  |                                                  |
| **Costs and expenses**                                                     |                                             |                                                  |                                                  |
| Production costs and taxes                                                 | **4,322,833**                                    | 3,287,233                                             | 3,046,460                                             |
| Depreciation, depletion and amortization                                   | **1,631,468**                                    | 1,911,416                                             | 1,605,043                                             |
| General and administrative                                                 | **1,417,001**                                    | 1,293,109                                             | 1,322,616                                             |
| Interest expense                                                           | **333,198**                                      | 168,590                                               | 472,655                                               |
| Public relations                                                           | **21,605**                                       | 26,037                                                | 30,020                                                |
| Professional fees                                                          | **232,197**                                      | 173,932                                               | 263,800                                               |
| Total costs and expenses                                                   | **7,958,302**                                    | 6,860,317                                             | 6,740,594                                             |
|                                                                       |                                             |                                                  |                                                  |
| **Net Operating Income**                                                   | **1,410,322**                                    | 2,141,364                                             | 432,282                                               |
|                                                                       |                                             |                                                  |                                                  |
| Deferred Tax Benefit                                                       | **2,100,000**                                    | -                                                     | -                                                     |
| Gain on Preferred Stock                                                    | **-**                                            | -                                                     | 655,746                                               |
|                                                                       |                                             |                                                  |                                                  |
|                                                                       |                                             |                                                  |                                                  |
| **Net Income**                                                             | **$**     **3,510,322** | $     2,141,364              | $     1,088,028              |
|                                                                       |                                             |                                                  |                                                  |
|                                                                       |                                             |                                                  |                                                  |
| **Net Income per share**

Basic and diluted:                               |                                             |                                                  |                                                  |
| Operations                                                                 | **$**     **0.06**      | $       0.04  | $       0.02  |
| Total                                                                      | **$**     **0.06**      | $       0.04  | $       0.02  |
|                                                                       |                                             |                                                  |                                                  |
| **Shares used in computing earnings per                            share** |                                             |                                                  |                                                  |
| Basic                                                                      | **59,117,176**                                   | 58,851,883                                            | 52,019,051                                            |
| Diluted                                                                    | **60,827,224**                                   | 60,364,797                                            | 52,659,051                                            |

 

*See accompanying Notes to Consolidated Financial            Statements*

 

 

**F-6**

 

----

Tengasco, Inc. and Subsidiaries

**Consolidated Statements of Stockholders’ Equity**

 

 

|                                          | ***Common Stock*** |         | ***Paid-In******Capital*** |    | ***Accumulated******Deficit*** |   | ***Total*** |   |   |
|-----------------------------------------------|--------------------|--------------|----------------------------|---------|--------------------------------|--------|-------------|--------|--------|
| ***Shares***                                  |               | ***Amount*** |                       |
|                                          |               |         |                       |    |                           |   |        |   |   |   |   |   |   |   |   |
| Balance, January 1, 2005                      | 48,927,828         |         |                       | 48,928  |                           |   | 51,686,283  |   |   | (33,385,524 | ) |   |   | 18,349,687 |   |
|                                          |               |         |                       |    |                           |   |        |   |   |   |   |   |   |   |   |
| Net Income                                    | —            |         |                       | — |                           |   | —     |   |   | 1,088,028 |   |   |   | 1,088,028 |   |
| Common Stock issued for exercised options     | 100,000            |         |                       | 100     |                           |   | 26,900      |   |   | — |   |   |   | 27,000 |   |
| Options Expense                               | —            |         |                       | — |                           |   | 84,030      |   |   | — |   |   |   | 84,030 |   |
| Lawsuit Settlement                            | 4,000              |         |                       | 4       |                           |   | 19,366      |   |   | — |   |   |   | 19,370 |   |
| Conversion of Stock                           | 9,567,620          |         |                       | 9,568   |                           |   | 2,381,418   |   |   | — |   |   |   | 2,390,986 |   |
| Common Stock issued for exercise of

Warrants | 5,230              |         |                       | 5       |                           |   | 2,348       |   |   | — |   |   |   | 2,353 |   |
| Balance, December 31, 2005                    | 58,604,678         |         |                       | 58,605  |                           |   | 54,200,345  |   |   | (32,297,496 | ) |   |   | 21,961,454 |   |
|                                          |               |         |                       |    |                           |   |        |   |   |   |   |   |   |   |   |
| Net Income                                    | -                  |         |                       | -       |                           |   | -           |   |   | 2,141,364 |   |   |   | 2,141,364 |   |
| Options & compensation expense            | 364,500            |         |                       | 365     |                           |   | 301,674     |   |   | — |   |   |   | 302,039 |   |
| Common stock issued for exercise of warrants  | 34,106             |         |                       | 34      |                           |   | 15,314      |   |   | — |   |   |   | 15,348 |   |
| Balance, December 31, 2006                    | 59,003,284         |         |                       | 59,004  |                           |   | 54,517,333  |   |   | (30,156,132 | ) |   |   | 24,420,205 |   |
|                                          |               |         |                       |    |                           |   |        |   |   |   |   |   |   |   |   |
| Net Income                                    | -                  |         |                       | -       |                           |   | -           |   |   | 3,510,322 |   |   |   | 3,510,322 |   |
| Options & compensation expense            | 145,250            |         |                       | 145     |                           |   | 168,951     |   |   | - |    |   |   | 169,096 |   |
| Common stock issued for exercise of warrants  | 7,216              |         |                       | 7       |                           |   | 3,241       |   |   | - |   |   |   | 3,248 |   |
| Balance, December 31, 2007                    | 59,155,750         |         |                       | 59,156  |                           |   | 54,689,525  |   |   | (26,645,810) |   |   |   | 28,102,871 |   |
|                                               |                    |              |                            |         |                                |        |             |        |        |  |  |  |  |  |  |  |  |

 

*See accompanying Notes to Consolidated Financial            Statements*

 

 

**F-7**

 

----

Tengasco, Inc. and Subsidiaries

**Consolidated Statements of Cash Flows**

 

 

|                                                                                                                                                                                        | **2007**                         | **2006**                                       | 2005                                     |   |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|----------------------------------|------------------------------------------------|------------------------------------------|--------|
| **Operating activities**                                                                                                                                                                    |                             |                                           |                                     |   |
| Net                                                                                                                                                                               |   $**3,510,322**       | **$**    **2,141,364**     | $     1,088,028 |   |
| Adjustments to reconcile net income to net                            cash

Provided by operating activities:                                                                               |                             |                                           |                                     |   |
| Depletion, depreciation, and amortization                                                                                                                                                   | **1,631,468**                    | **1,911,416**                                  | 1,605,043                                |   |
| Accretion of redeemable shares                                                                                                                                                              | **-**                            | **-**                                          | 242,008                                  |   |
| Accretion on Asset Retirement Obligation                                                                                                                                                    | **70,929**                       | **42,340**                                     | 45,965                                   |   |
| Gain on extinguishment of Asset Retirement                            Obligation                                                                                                            | **-**                            | **-**                                          | (72,399)                                 |   |
| (Gain)/loss on sale of vehicles/equipment                                                                                                                                                   | **5,740**                        | **(22,466)**                                   | (15,330)                                 |   |
| Gain on exchange of Redeemable Liabilities                                                                                                                                                  | **-**                            | **-**                                          | (655,746)                                |   |
| Gain on sale of pipeline facilities                                                                                                                                                         | **-**                            | **-**                                          | (17,605)                                 |   |
| Compensation and services paid in stock                            options                                                                                                                  | **116,476**                      | **159,160**                                    | 103,400                                  |   |
| Deferred Tax Benefit                                                                                                                                                                        | **(2,100,000)**                  | **-**                                          | -                                        |   |
| Changes in assets and liabilities:                                                                                                                                                          |                             |                                           |                                     |   |
| Accounts receivable                                                                                                                                                                         | **(337,308)**                    | **434,565**                                    | (447,653)                                |   |
| Participant receivables                                                                                                                                                                     | **(36,864)**                     | **(3,231)**                                    | 63,239                                   |   |
| Other current assets                                                                                                                                                                        | **-**                            | **(5,000)**                                    | 61,470                                   |   |
| Inventory                                                                                                                                                                                   | **90,157**                       | **(54,191)**                                   | (154,586)                                |   |
| Accounts payable                                                                                                                                                                            | **215,763**                      | **90,197**                                     | 277,458                                  |   |
| Accrued interest payable                                                                                                                                                                    | **1,573**                        | **8,432**                                      | (25,367)                                 |   |
| Other accrued liabilities                                                                                                                                                                   | **330,264**                      | **(251,327)**                                  | 70,115                                   |   |
| Settlement on Asset Retirement Obligations                                                                                                                                                  | **(51,843)**                     | **(97,293)**                                   | (54,277)                                 |   |
| Net cash provided by operating activities                                                                                                                                                   | **3,446,677**                    | **4,353,966**                                  | 2,113,763                                |   |
|                                                                                                                                                                                        |                             |                                           |                                     |   |
| **Investing activities**                                                                                                                                                                    |                             |                                           |                                     |   |
| Additions to other property & equipment                                                                                                                                                 | **(172,443)**                    | **(137,924)**                                  | (210,145)                                |   |
| Restricted cash                                                                                                                                                                             | **-**                            | **(120,500)**                                  | -                                        |   |
| Decrease to other property & equipment                                                                                                                                                  | **17,000**                       | **27,915**                                     | 55,919                                   |   |
| Net additions to oil and gas properties                                                                                                                                                     | **(5,190,611)**                  | **(5,239,862)**                                | (2,348,078)                              |   |
| Sale of Kansas gas field                                                                                                                                                                    | **-**                            | **-**                                          | 2,651,770                                |   |
| Additions to Methane Project                                                                                                                                                                | **(1,649,710)**                  |                                           |                                     |   |
| Drilling program portion of additional                            drilling                                                                                                                  | **3,850,000**                    | **1,067,400**                                  | 1,945,202                                |   |
| (Increase)/decrease in pipeline facilities                                                                                                                                                  | **-**                            | **(10,214)**                                   | 72,186                                   |   |
| Net cash provided by (used in) investing                            activities                                                                                                              | **(3,145,764)**                  | **(4,413,185)**                                | 2,166,854                                |   |
|                                                                                                                                                                                        |                             |                                           |                                     |   |
| **Financing activities**                                                                                                                                                                    |                             |                                           |                                     |   |
| Proceeds from exercise of options/warrants                                                                                                                                                  | **55,867**                       | **158,227**                                    | 29,352                                   |   |
| Proceeds from borrowings                                                                                                                                                                    | **1,696,444**                    | **2,732,145**                                  | 155,073                                  |   |
| Loan fees                                                                                                                                                                                   | **(77,467)**                     | **(285,224)**                                  | **-**                                    |   |
| Repayments of borrowings                                                                                                                                                                    | **(118,583)**                    | **(112,833)**                                  | (3,182,636)                              |   |
| Proceeds from issuance of common stock                                                                                                                                                      | **-**                            | **-**                                          | 2,391,905                                |   |
| Dividends paid on Redeemable Liabilities                                                                                                                                                    | **-**                            | **-**                                          | (8,000)                                  |   |
| Repayments of Redeemable Liabilities                                                                                                                                                        | **-**                            | **-**                                          | (4,241,874)                              |   |
| New Drilling Program                                                                                                                                                                        | **-**                            | **-**                                          | 2,514,000                                |   |
| Decrease in Drilling Program liability                                                                                                                                                      |                             | **(2,324,400)**                                | (1,945,203)                              |   |
| Net cash provided by (used in) financing                            activities                                                                                                              | **1,556,261**                    | **167,915**                                    | (4,287,383)                              |   |
|                                                                                                                                                                                        |                             |                                           |                                     |   |
| Net change in cash and cash equivalents                                                                                                                                                     | **1,857,174**                    | **108,696**                                    | (6,766)                                  |   |
|                                                                                                                                                                                        |                             |                                           |                                     |   |
| Cash and cash equivalents, beginning of                            period                                                                                                                   | **369,665**                      | **260,969**                                    | 267,735                                  |   |
| Cash and cash equivalents, end of                            period                     |  $**2,226,839  ** | **$**     **369,665** | $     260,969   |   |
|                                                                                                                                                                                             |                                  |                                                |                                          |        |  |  |

 

 

**F-8**

 

----

|   |   |
|--------|--------|

****                                                 Tengasco,            Inc. and Subsidiaries****

**Notes to Consolidated Financial Statements**     

 

|   | **(1.)** | **Summary of Significant Accounting                            Policies** |
|--------|----------|---------------------------------------------------------------------------|

             

The Company was initially organized in Utah in 1916 for the purpose of            mining, reducing and smelting mineral ores, under the name Gold Deposit Mining &            Milling Company, later changed to Onasco Companies, Inc. In 1995, the Company changed            its name from Onasco Companies, Inc. to Tengasco, Inc., by merging into Tengasco, Inc.,            a Tennessee corporation, formed by the Company solely for this purpose.

 

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

             

In 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 Company sold the Kansas gas producing wells, gathering system and            compressors effective February 1, 2005. During 2007, the Kansas Properties produced an            average of 14,860 gross barrels of oil per month.

             

The Company’s activities in oil and gas leases in Tennessee are            located in Hancock, Claiborne, and Jackson counties. The Company has drilled primarily            on a portion of its leases known as the Swan Creek Field in Hancock County focused            within what is known as the Knox Formation, one of the geologic formations in that            field. During 2007, the Company produced an average of 347 thousand cubic feet of            natural gas per day and 573 barrels of oil per month from 21 producing gas wells and 5            producing oil wells in the Swan Creek Field.

             

The Company’s wholly-owned subsidiary, Tengasco Pipeline            Corporation (“TPC”) owns and operates a 65-mile intrastate pipeline which            it constructed to transport natural gas from the Company’s Swan Creek Field to            customers in Kingsport, Tennessee.

             

The Company formed a wholly-owned subsidiary on December 27, 2006 named            Manufactured Methane Corporation for the purpose of owning and operating treatment and            delivery facilities using the latest developments in available treatment technologies            for the extraction of methane gas from nonconventional sources for delivery through the            nation’s existing natural gas pipeline system, including the Company’s TPC            pipeline system in Tennessee for eventual sale to natural gas customers.

 

 

**F-9**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

**Basis of Presentation**

             

The accompanying consolidated financial statements have been prepared in            conformity with accounting principles generally accepted in the United States of            America, which contemplate continuation of the Company as a going concern and assume            realization of assets and the satisfaction of liabilities in the normal course of            business.

             

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

             

**Use of Estimates**

             

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

             

**Revenue Recognition**

             

The Company uses the sales method of accounting for natural gas and oil            revenues. Under this method, revenues are recognized based on actual volumes of oil and            gas sold to purchasers. Natural gas meters are placed at the customers’ locations            and usage is billed monthly.

             

**Cash and Cash Equivalents**

             

The Company considers all investments with a maturity of three months or            less when purchased to be cash equivalents.

             

**Inventory**

             

Inventory consists of crude oil in tanks and is carried at lower of cost            or market value.

 

**F-10**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

**Oil and Gas Properties**

             

The Company follows the full cost method of accounting for oil and gas            property acquisition, exploration, and development activities. Under this method, all            productive and nonproductive costs incurred in connection with the acquisition of,            exploration for and development of oil and gas reserves for each cost center are            capitalized. Capitalized costs include lease acquisitions, geological and geophysical            work, delay rentals and the costs of drilling, completing, equipping and plugging oil            and gas wells. Gains or losses are recognized only upon sales or dispositions of            significant amounts of oil and gas reserves representing an entire cost center.            Proceeds from all other sales or dispositions are treated as reductions to capitalized            costs.

             

The capitalized costs of oil and gas properties, plus estimated future            development costs relating to proved reserves and estimated costs of plugging and            abandonment, net of estimated salvage value, are amortized on the unit-of-production            method based on total proved reserves. The Company currently has $3,110,768 in            unevaluated properties as of December 31, 2007. The costs of unproved properties are            excluded from amortization until the properties are evaluated, subject to an annual            assessment of whether impairment has occurred. The Company has determined its reserves            based upon reserve reports provided by Ryder Scott Company, Petroleum Consultants in            2005 , and by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.

             

The capitalized oil and gas properties, less accumulated depreciation,            depletion and amortization and related deferred income taxes, if any, are generally            limited to an amount (the ceiling limitation) equal to the sum of: (a) the present            value of estimated future net revenues computed by applying current prices in effect as            of the balance sheet date (with consideration of price changes only to the extent            provided by contractual arrangements) to estimated future production of proved oil and            gas reserves, less estimated future expenditures (based on current costs) to be            incurred in developing and producing the reserves using a discount factor of 10% and            assuming continuation of existing economic conditions; and (b) the cost of investments            in unevaluated properties excluded from the costs being amortized. The Company has            adopted an SEC accepted method of calculating the full cost ceiling test whereby the            liability recognized under Statement of Financial Accounting Standard No. 143            (“SFAS”) “Accounting for Asset Retirement Obligation”            (“SFAS 143”) is netted against property cost and the future abandonment            obligations are included in estimated future net cash flows.No            ceiling write-downs were recorded in 2007, 2006, or 2005.

             

**Pipeline Facilities**

             

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

             

**Other Property and Equipment and Long - Lived Assets**

             

Other property and equipment are carried at cost. The Company provides            for depreciation of other property and equipment using the straight-line method over            the estimated useful lives of the assets which range from three to seven years.            Long-lived assets (other than oil and gas properties) are reviewed for impairment            whenever events or changes in circumstances indicate that the carrying amount may not            be recoverable.

 

**F-11**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

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, 2007, management believes that carrying amounts of            all of the Company’s long-lived assets will be fully recovered over the course of            the Company’s normal future operations.

             

**Stock-Based Compensation**

             

The Company recorded $100,877 in 2007, $128,197 in 2006 and $84,030 in            compensation expense in 2005 upon the Company’s adoption of SFAS 123 (R) in            2005.

             

**Accounts Receivable**

             

Senior management reviews accounts receivable on a monthly basis to            determine if any receivables will potentially be uncollectible. Based on the            information available to us, the Company believes no allowance for doubtful            accounts as of December 31, 2007 and 2006 is necessary. However, actual write-offs may            occur.

             

**Income Taxes**

             

The Company accounts for income taxes using the “asset and            liability method.” Accordingly, deferred tax liabilities and assets are            determined based on the temporary differences between the financial reporting and tax            bases of assets and liabilities, using enacted tax rates in effect for the year in            which the differences are expected to reverse. Deferred tax assets arise primarily from            net operating loss carry-forwards. Management evaluates the likelihood of realization            for such assets at year-end providing a valuation allowance for any such amounts not            likely to be recovered in future periods. The Company currently has a net operating            loss carry forward of 21,100,000.

             

|   | **Concentration of Credit Risk** |
|--------|----------------------------------|

 

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

             

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

 

 

**F-12**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

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

             

The Company has entered into contracts to supply two manufacturers with            natural gas from the Swan Creek Field (Tennessee) through the Company’s pipeline.            These customers are the Company’s primary customers for natural gas sales.            Additionally, the Company sells a majority of its crude oil primarily to two customers,            one each in Tennessee and Kansas. Although management believes that customers could be            replaced in the ordinary course of business, if the present customers were to            discontinue business with the Company, it could have a significant adverse effect on            the Company’s projected results of operations.

             

In 2007, the Company received 91.4 percent of its revenues from Customer            A; 4.9 percent of its revenues from Customer B; and 3.7 percent of its revenues from            Customer C.

 

In 2006, the Company received 85.7 percent of its revenues from Customer            A; 10.1 percent of its revenues from Customer B.

 

In 2005, the Company received 74.6 percent of its revenues from Customer            A; 18.6 percent of its revenues from Customer B.

             

In each of the years 2005 through 2007, the identity of the customers            indicated above as either A, B or C was the same from year to year, although the            percentage of revenues varied from year to year for those customers.

 

|   | **Income per Common Share** |
|--------|-----------------------------|

 

In accordance with Statement of Financial Accounting Standards (SFAS)            No. 128, “Earnings Per Share” (“SFAS 128”), basic income per            share is based on 59,117,176, 58,851,883 and 52,019,051 weighted average shares            outstanding for the years ended December 31, 2007, December 31, 2006 and December 31,            2005 respectively. Diluted earnings per common share are computed by dividing income            available to common shareholders by the weighted average number of shares of common            stock outstanding during the period increased to include the number of additional            shares of common stock that would have been outstanding if the dilutive potential            shares of common stock had been issued. The dilutive effect of outstanding options and            warrants is reflected in diluted earnings per share.

 

 

**F-13**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

The number of dilutive shares outstanding is 1,710,048 for 2007,            1,512,914 for 2006 and 640,000 for 2005. These are related to options and            warrants.

             

**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.

             

**(2.) Recent Accounting Pronouncements**

 

In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting            for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"),            which clarifies the accounting for uncertainty in tax positions taken or expected to be            taken in a tax return, including issues relating to financial statement recognition and            measurement. FIN 48 provides that the tax effects from an uncertain tax position can be            recognized in the financial statements only if the position is "more-likely-than-not"            to be sustained if the position were to be challenged by a taxing authority. The            assessment of the tax position is based solely on the technical merits of the position,            without regard to the likelihood that the tax position may be challenged. If an            uncertain tax position meets the "more-likely-than-not" threshold, the largest amount            of tax benefit that is more than 50 percent likely to be recognized upon ultimate            settlement with the taxing authority, is recorded. The provisions of FIN 48 are            effective for fiscal years beginning after December 15, 2006, with the cumulative            effect of the change in accounting principle recorded as an adjustment to opening            retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on            January 1, 2007. The adoption of FIN 48 had no impact on our results of operations or            financial position. The Company currently has open tax return periods beginning with            December 31, 2004 through December 31, 2007.

             

In September 2006, the Securities and Exchange Commission staff            published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering            the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year            Financial Statements." SAB 108 addresses quantifying the financial statement effects of            misstatements, specifically, how the effects of prior year uncorrected errors must be            considered in quantifying misstatements in the current year financial statements. SAB            108 is effective for fiscal years ending after November 15, 2006. The Company adopted            SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the            Company’s consolidated financial statements.

             

In September 2006, the FASB issued SFAS 157, Fair Value Measurements.            The standard provides guidance for using fair value to measure assets and liabilities.            It defines fair value, establishes a framework for measuring fair value under generally            accepted accounting principles and expands disclosures about fair value            measurement

 

**F-14**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

Under the standard, fair value refers to the price that would be            received to sell an asset or paid to transfer a liability in an orderly transaction            between market participants in the market in which the reporting entity transacts. It            clarifies the principle that fair value should be based on the assumptions market            participants would use when pricing the asset or liability. In support of this            principle, the standard establishes a fair value hierarchy that prioritizes the            information used to develop those assumptions. Under the standard, fair value            measurements would be separately disclosed by level within the fair value hierarchy.            Statement 157 is effective for financial statements issued for fiscal years beginning            after November 15, 2007. The Company continues to evaluate the impact the adoption of            this statement could have on its financial condition, results of operations and cash            flows.

             

In February 2007, the FASB issued SFAS No. 159 “The Fair Value            Option for Financial Assets and Financial Liabilities — as amended (“SFAS            159”). SFAS 159 permits entities to elect to report eligible financial            instruments at fair value subject to conditions stated in the pronouncement including            adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial            reporting by mitigating volatility in earnings related to current reporting            requirements. The Company is considering the applicability of SFAS 159 and will            determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal            years beginning after November 15, 2007.

             

|   | **(3).** | **Related Party Transactions** |
|--------|----------|--------------------------------|

             

In October, 2005 the Company accepted an exchange from Hoactzin of            promissory notes made by the Company in the principal amount of $2,514,000 for a 94.3%            working interest in a twelve well drilling program (the “Twelve Well            Program”) by the Company on its Kansas Properties. The Company retained the            remaining 5.7% working interest in the Twelve Well Program. The promissory notes            exchanged were originally issued by the Company in connection with loans made to the            Company by Dolphin Offshore Partners, L.P. to fund the Company’s cash exchange to            holders of its Series A, B and C Preferred Stock.

             

In 2006, the Company drilled four wells in the Twelve Well Program            bringing the total number of wells drilled in that Program to six. All but one of those            wells is continuing to produce commercial quantities of oil.

On June 29th, 2006 the Company closed a $50,000,000 credit facility with            Citibank Texas, N.A. The Company’s initial borrowing base was set at $2,600,000            and the Company borrowed that amount on June 29, 2006 and used $1.393 million of the            loan proceeds to exercise its option to repurchase from Hoactzin, the Company’s            obligation to drill the final six wells in the Company’s Twelve Well Program. As            a result of the repurchase, the Twelve Well Program was converted to a six well            program, all of which had been drilled by the Company at the time of the repurchase.            Consequently, all well-drilling obligations of the Company under both the Eight Well            and Twelve Well Programs with former preferred stockholders as participants have been            satisfied.

 

**F-15**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

If the Company had not exercised its repurchase option, Hoactzin would            have received a 94% working interest in the final six wells of the Twelve Well Program.            However, as a result of the repurchase, Hoactzin will now receive only a 6.25%            overriding royalty in six Company wells to be drilled, plus an additional 6.25%            overriding royalty in the six program wells that had previously been drilled as part of            the Twelve Well Program.

 

On September 17, 2007, the Company entered into a drilling program with            Hoactzin for ten wells consisting of approximately three wildcat wells and seven            developmental wells to be drilled on the Company’s Kansas Properties (the            “Program”). Under the terms of the Program, Hoactzin was to pay the Company            $400,000 for each well in the Program completed as a producing well and $250,00 per            drilled well that was non-productive. The terms of Program also provide that Hoactzin            will receive all the working interest in the ten wells in the Program, but will pay an            initial fee to the Company of 25% of its working interest revenues net of operating            expenses. This is referred to as a management fee but as defined is in the nature of a            net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of            working interest revenues when net revenues received by Hoactzin reach an agreed payout            point of approximately 1.35 times Hoactzin’s purchase price (the “Payout            Point”). The Company will account for funds received for interests in the Program            as an offset to oil and gas properties.

 

As of the date of this Report, the Company has drilled all ten wells in            the Program. Of the ten wells drilled, nine were completed as oil producers and are            currently producing approximately 84 barrels per day in total. Hoactzin paid a total of            $3,850,000 for its interest in the Program resulting in the Payout Point being            determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program            wells exceeded the Company’s actual drilling costs of approximately $2.8 million            for the ten wells by more than $1 million.

 

Although production level of the Program wells will decline with time in            accordance with expected decline curves for these types of well, based on the drilling            results of the Program wells and the current price of oil, the Program wells are            expected to reach the Payout Point in approximately four years solely from the oil            revenues from the wells. However, under the terms of its agreement with Hoactzin            reaching the Payout Point has been accelerated by Hoactzin agreeing to apply 75% of the            net proceeds it receives from the methane extraction project being developed by the            Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the            Carter Valley, Tennessee landfill to the Payout Point. (The methane extraction project            is discussed in greater detail below.) Those methane project proceeds when applied will            result in the Payout Point being achieved sooner than the estimated four year period            based solely upon revenues from the Program wells.

             

 

**F-16**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

On December 18, 2007, the Company entered into a Management Agreement            with Hoactzin. On that same date, the Company also entered into an agreement with            Charles Patrick McInturff employing him as a Vice-President of the Company. Pursuant to            the Management Agreement with Hoactzin, Mr. McInturff’s duties while he is            employed as Vice-President of the Company will include the management on behalf of            Hoactzin of its working interests in certain oil and gas properties owned by Hoactzin            and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana.            As consideration for the Company entering into the Management Agreement, Hoactzin has            agreed that it will be responsible to reimburse the Company for the payment of one-half            of Mr. McInturff’s salary, as well as certain other benefits he receives during            his employment by the Company. In further consideration for the Company’s            agreement to enter into the Management Agreement, Hoactzin has granted to the Company            an option to participate in up to a 15% working interest on a dollar for dollar cost            basis in any new drilling or work-over activities undertaken on Hoactzin’s            managed properties during the term of the Management Agreement. The term of the            Management Agreement is the earlier of the date Hoactzin sells its interests in its            managed properties or 5 years.

             

| **4.** | **Oil and Gas Properties** |
|--------|----------------------------|

 

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

             

| *December 31,*                                         | **2007**                | 2006                    |
|--------------------------------------------------------|-------------------------|-------------------------|
| Oil and gas properties, at cost                        | **18,856,487**          | $  18,745,834 |
| Unevaluated properties                                 | **3,110,768**           | 1,880,811               |
| Accumulation depreciation,

depletion and amortization |  

**(8,757,654)** |  

(7,923,016)     |
| Oil and gas properties, net                            | **13,209,601**          | $  12,703,629 |
|                                                   |                    |                    |

             

During the years ended December 31, 2007, 2006 and 2005 the Company            recorded depletion expense of $834,638, $1,144,711 and $902,131 in 2005.

 

| **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 transportation 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 $544,000, $544,000            and $536,000, in depreciation expense related to the pipeline for the years ended            December 31, 2007, 2006 and 2005, respectively.

 

**F-17**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

In January 1997, the Company entered into an agreement with the            Tennessee Valley Authority (“TVA”) whereby the TVA allows the Company to            bury the pipeline within the TVA’s transmission line rights-of-way. In return for            this right, the Company paid $35,000 and agreed to annual payments of approximately            $6,200 for 20 years.

 

This agreement expires in 2017 at which time the parties may renew the            agreement for another 20-year term in consideration of similar inflation-adjusted            payment terms.

             

| **6.**

****Other                            Property****

****and                            Equipment**** |   |   |
|-------------------------------------------------------------------------------------------------------------|--------|--------|

             

Other property and equipment consisted of the following:

 

| *December 31*                      | *Depreciable Life* | **2007**                               | 2006                              |
|------------------------------------|--------------------|----------------------------------------|-----------------------------------|
|                               |               |                                   |                              |
| Machinery and equipment            | 5-7 yrs            | $     830,734 | $     771,767 |
| Vehicles                           | 2-5 yrs            | 487,176                                | 521,824                           |
| Other                              | 5 yrs              | 63,734                                 | 63,734                            |
| Total                              |               | 1,381,644                              | 1,357,325                         |
| Less accumulated depreciation      |               | (1,125,586)                            | (1,089,612)                       |
| Other property and equipment - net |               | $     256,058 | $     267,713 |

 

The Company uses the straight-line method of depreciation ranging from            two years to seven years, depending on the asset life.

| **7.** | **Long Term Debt** |
|--------|--------------------|

             

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

             

| *December 31,*                                                                                                                                                                                                                                                            | **2007**                                                                                                                        | **2006**                                                                                                                        |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------|
| Note payable to a financial institution, with interest                            payment only until maturity.

(See Notes 15 & 16)

                                                                                                                            |  

                             

**$4,200,000**                                                                      |  

                             

$   2,600,000                                                        |
| Installment notes bearing                            interest at the rate of 5.5% to 8.25% per annum collateralized by                            vehicles with monthly payments including interest of approximately                            $10,000 due through 2010. |  

                             

                             

                             

**173,660** |  

                             

                             

                             

**195,801** |
| Total long-term debt                                                                                                                                                                                                                                                      | **4,373,660**                                                                                                                   | **2,795,801**                                                                                                                   |
| Less current maturities                                                                                                                                                                                                                                                   | **(57,887)**                                                                                                                    | **(65,267)**                                                                                                                    |
| Long-term debt, less current

maturities                                                                                                                                                                                                                                  |  

**4,315,773**                                                                                                           |  

$   **2,730,534**                                                                                        |

 

 

 

**F-18**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

| **8.** | **Commitments and Contingencies** |
|--------|-----------------------------------|

             

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

             

In the ordinary course of business the Company has entered into office            leases which have remaining term of 6 months. Approximate future minimum lease payments            to be made under non-cancelable operating leases in 2008 are $31,673.

             

Office rent expense for each of the three years ended December 31, 2007,            2006 and 2005 was approximately $63,346, $63,346, and $ 83,332 respectively.

             

| **9.** | **Cumulative Convertible Redeemable** |
|--------|---------------------------------------|

|   | **Preferred Stock** |
|--------|---------------------|

             

On August 22, 2005 all holders of the Company's Series B and C            Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having a            total aggregate value of $5,113,045 consisting of face value, dividends, and interest            exchanged all rights under their Series B and C shares for cash or for the Company's            common stock. As a result of the exchange, as of August 22, 2005 the Company no longer            had any holders of Series B or C preferred stock and no further obligations under any            Series B or C shares. Holders of approximately 53.2% of the face value of outstanding            Series B and C shares exchanged their preferred shares having an aggregate value of            $2,721,140 for cash payments totaling $1,814,184. The Company obtained the funds for            this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin. The loan            from Dolphin was evidenced by a secured promissory note dated August 22, 2005 bearing            12% interest per annum payable interest only monthly until the principal amount of the            note was to become due on December 31, 2005. A second option offered to the Series B            and C holders was to exchange their Series B and C shares for four shares of the            Company's common stock for each dollar of the face value and unpaid accrued dividends            and interest on their Series B and C shares. All of the holders, including Dolphin, of            the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares            selected this option. As a result, a total of 9,567,620 shares of the Company's common            stock were issued to those holders. Of this total number, 4,595,040 shares of            unregistered common stock were issued to Dolphin in exchange for the $1,148,760 in            aggregate value of the Series B shares held by Dolphin.

 

In total, the Company recorded a gain during 2005 from the exchange of            Series A, B and C shares for cash and stock of $655,746, the difference between the            carrying amount and the cash settlement amount and the stock issued.

             

 

**F-19**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

| **10.** | **Asset Retirement Obligation** |
|---------|---------------------------------|

 

The Company follows 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 required            that upon initial application of these standards, the Company must recognize a            cumulative effect of a change in accounting principle corresponding to the accumulated            accretion and depletion expense that would have been recognized had this standard been            applied at the time the long-lived assets were acquired or constructed. The            Company’s asset retirement obligations relate primarily to the plugging,            dismantling and removal of wells drilled to date. The Company’s calculation of            Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated            useful life of wells ranging from 30-40 years, estimated plugging and abandonment cost            range from $5,000 per well to $10,000 per well. Management continues to periodically            evaluate the appropriateness of these assumptions.

             

On March 4, 2005 the Company sold its Kansas gas wells, and consequently            the asset and the corresponding liability relating to asset retirement obligations on            these wells were extinguished. The asset account was credited for $60,998 and the            liability was removed in the amount of $133,397, creating a gain on the extinguishment            of future obligations in the amount of $72,399, which was credited to interest            expense.

             

The following is a roll-forward of activity impacting the asset            retirement obligation for the year ended December 31, 2007:

             

| Balance, December 31, 2005 | $      566,968 |
|----------------------------|----------------------------------------------|
| Accretion expense          | 42,340                                       |
| Liabilities Settled        | (97,293)                                     |
| Balance, December 31, 2006 | $      512,015 |
| Accretion expense          | 70,929                                       |
| Liabilities Settled        | (51,843)                                     |
| Balance, December 31, 2007 | $      531,101 |

 

| **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 participants under the plan shall not exceed            3,500,000. Options are not transferable, are exercisable for 3 months after            voluntary

 

**F-20**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

resignation from the Company, and terminate immediately upon involuntary            termination from the Company. The purchase price of shares subject to this plan shall            be determined at the time the options are granted, but are not permitted to be less            than 85% of the fair market value of such shares on the date of grant. Furthermore, a            participant 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 a participant            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 2007, 2006 and 2005 is summarized            below:

             

| ***2007***                                            |                                                                                          | *2006*                                                                                       |                                                                                     | *2005*                                                                   |                                                                                     |
|-------------------------------------------------------|-----------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------|--------------------------------------------------------------------------|------------------------------------------------------------------------------------------|
|                                                  |  

                             

                             

*Shares*      | *Weighted*

*Average*

*Exercise*

*Price*                                                   |  

                             

                             

*Shares* | *Weighted*

*Average*

*Exercise*

*Price*                               |  

                             

                             

*Shares* | *Weighted*

*Average*

*Exercise*

*Price* |
| **Outstanding**,

beginning of

year                  |  

                             

                             

**2,596,000** |  

                             

**$**      **.31** |  

                             

2,584,000                                    |  

                             

$    .29 |  

                             

295,153                                      |  

                             

$    1.26 |
| Granted                                               | **0**                                                                                         |                                                                                         | 350,000                                                                                  | .60                                                                      | 2,500,000                                                                                | .27 |
| Exercised                                             | **(126,000)**                                                                                 | **.42**                                                                                      | (338,000)                                                                                | .42                                                                      | (100,000)                                                                                | .27 |
| Expired/

canceled                                    |  

**(29,000)**                                                                          |  

**.64**                                                                              |  

-                                                                                |  

-                                                                |  

(111,153)                                                                        |  

2.52 |
| **Outstanding**

and 

exercisable,

end of year |  

                             

**2,441,000**                                     |  

                             

**$**      **.30** |  

                             

2,596,000                                    |  

                             

$    .31 |  

                             

2,584,000                                    |  

                             

$     .29 |

             

The following table summarizes information about stock options            outstanding and exercisable at December 31, 2006:

             

|   |                                         | *Options Outstanding*                                                                                                        |                                                           | *Options Exercisable*                                                                                                        |
|--------|----------------------------------------------|------------------------------------------------------------------------------------------------------------------------------|----------------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------|
|   |  

*Weighted Average*

*Exercise Price* |  

                             

                             

                             

*Shares* | *Weighted Average*

*Remaining*

*Contractual*

*Life (years)* |  

                             

                             

                             

*Shares* |
|   | $    0.27                | 2,251,000                                                                                                                    | 2.33                                                           | 1,357,000                                                                                                                    |
|   | $    0.58                     | 110,000                                                                                                                      | 3.05                                                           | 110,000                                                                                                                      |
|   | $    0.81                | 80,000                                                                                                                       | 3.93                                                           | 80,000                                                                                                                       |

 

 

**F-21**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

The weighted average fair value per share of options granted during 2006            and 2005 range from $0.15 to $0.32, calculated using the Black-Scholes Option-Pricing            model. No options were granted in 2007.

             

Compensation expense of $84,030 related to stock options was recognized            in 2005 and $128,197 in 2006 and 100,877 in 2007.

             

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            2006 and 2005: expected volatility of 60% for 2006, and 2005; a risk free interest rate            of 3.67% in 2006 and 2005; and an expected option life of 2.5 years for 2006 and            2005.

             

| **12.** | **Income Taxes** |
|---------|------------------|

             

The Company has taxable income for the periods ending December 31, 2007,            December 31, 2006 and December 31, 2005.

             

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

             

| *December 31,*                                                                           | **2007**                | 2006                               | 2005                                                                                                                   |
|------------------------------------------------------------------------------------------|-------------------------|------------------------------------|------------------------------------------------------------------------------------------------------------------------|
|                                                                                     |                    |                               |                                                                                                                   |
| Statutory rate                                                                           | **34%**                 | 34%                                | 34%                                                                                                |
| Tax (benefit)/expense

at statutory rate                                                 |  

**1,193,000**   |  

$   728,000 |  

$   370,000                                                                                     |
| State income

tax (benefit)/expense                                                      |  

**140,000**     |  

85,000                     |                                           43,000 |
| Other                                                                                    | **3,000**               | 3,000                              | 3,000                                                                                                                  |
| Non-deductible interest                                                                  |                    |                               | -                                                                                                                      |
| Increase/(decreases)in deferred tax asset valuation                            allowance |  

**(3,436,000)** |  

(816,000)                  |  

(416,000)                                                                                                      |
| Total income tax provision (benefit)                                                     |  

**(2,100,000)** |  

-                          |  

-                                                                                                              |

 

 

 

**F-22**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

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

             

| December 31                     | **2007**        | 2006                   | 2005                   |
|---------------------------------|-----------------|------------------------|------------------------|
|                            |            |                   |                   |
| Deferred tax assets:            |            |                   |                   |
| Net operating loss carryforward | **$7,314,000**  | $  8,700,000 | $  9,616,000 |
| Capital loss carry forward      | **263,000**     | 263,000                | 263,000                |
| Total deferred tax assets       | **7,577,000**   | 8,963,000              | 9,879,000              |
| Deferred tax liability:         |            |                   |                   |
| Basis difference in pipeline    | **250,000**     | 300,000                | 400,000                |
| Total deferred liability        | **250,000**     | 300,000                | 400,000                |
| Total net deferred taxes        | **7,327,000**   | 8,663,000              | 9,479,000              |
| Valuation allowance             | **(5,227,000)** | (8,663,000)            | (9,479,000)            |
| Net deferred tax asset          | **$2,100,000**  | **-**                  | **-**                  |

             

As of December 31, 2007, Management, using the “more likely than            not” criteria for recognition, elected to recognize a deferred tax asset of $2.1            million. The recognition of the deferred tax asset in 2007 relates to net operating            loss carryforwards and will provide a better matching of income tax expense with            taxable income in future periods. The current provision reflects the recognition of            $1,336,000 current income tax benefit (fully offset by the current provision related to            2007 taxable income) and $2,100,000 in benefit relating to future periods.

             

No income tax expense was recognized for the years ended December 31,            2006 or December 31, 2005 because deferred tax benefits, derived from the            Company’s prior net operating losses, were previously fully reserved and were            being offset against tax liabilities that would otherwise arise from the results of            current operations. Management continuously estimates the realization of the            Company’s deferred tax assets based on its anticipation of the likely timing and            adequacy of future net income, after taking into consideration the increased            uncertainty attributed to a lengthening horizon before the projected realization of            future deferred assets.

             

As of December 31, 2007, the Company had net operating loss            carry-forwards of approximately $21,100,000 which will expire between 2011 and 2023 if            not utilized.

             

| **13.** | **Supplemental Cash Flow Information** |
|---------|----------------------------------------|

             

The Company paid approximately $262,268, $126,250, and $524,000, for            interest in 2007, 2006 and 2005, respectively. No interest was capitalized in 2007,            2006 or 2005. No income taxes were paid in 2007, 2006, or 2005.

             

 

**F-23**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

| **14.** | **Litigation Settlement** |
|---------|---------------------------|

             

On May 10, 2004 the Court entered its final order approving the fairness            of the settlement to the class, dismissing the action pursuant to a Settlement            Stipulation, and fully releasing the claims of the class members in*Paul Miller v. M. E. Ratliff and Tengasco, Inc.,*No. 3:02-CV-644 in the United States District Court for the Eastern            District of Tennessee, Knoxville, Tennessee. This action sought certification of a            class action to recover on behalf of a class of all persons who purchased shares of the            Company’s common stock between August 1, 2001 and April 23, 2002, unspecified            damages allegedly caused by violations of the federal securities laws. In January, 2004            all parties reached a settlement subject to court approval. The Court entered its order            approving the settlement on May 10, 2004. Under the settlement, the Company paid into a            settlement fund the amount of $37,500 to include all costs of administration,            contributed 150,000 shares of stock of Miller Petroleum, Inc. owned by the Company and            issued 300,000 warrants to purchase a share of the Company’s common stock for a            period of three years from date of issue at $1 per share subject to adjustments. The            Rights Offering adjusted this price to $0.45 per share. These Warrants expire on            September 12, 2008. 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.

 

| **15.** | **Bank Loan** |
|---------|---------------|

             

On June 29, 2006 the Company closed a $50,000,000 revolving senior            credit facility between the Company and Citibank Texas, N.A. in its own capacity and            also as agent for other banks.

             

Under the facility, loans and letters of credit will be available to the            Company on a revolving basis in an amount outstanding not to exceed the lesser of            $50,000,000 or the borrowing base in effect from time to time. The Company’s            initial borrowing base was set at $2,600,000. The initial loan under the facility with            Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing            interest at a floating rate equal to LIBOR plus 2.5%, resulting in an initial rate of            interest of approximately 8.2%. Interest only is payable during the term of the loan            and the principal balance of the loan is due thirty-six months from closing. The            facility is secured by a lien on substantially all of the Company’s producing and            non-producing oil and gas properties and pipeline assets. The facility has standard            loan covenants such as current ratios, interest coverage ratios etc, with which the            Company is in compliance.

 

 

**F-24**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

$1.393 million of the $2.6 million loan proceeds were used by the            Company on June 29, 2006 to exercise its option to repurchase from Hoactzin Partners,            L.P., the Company’s obligation to drill the final six wells in the            Company’s 12-well Kansas drilling program for Hoactzin. The Company incurred loan            closing costs consisting of legal fees, mortgage taxes, commissions and bank fees            totaling $285,224. This amount will be amortized over the term of the note and its            successor (See Note 16).

 

On April 19, 2007 the Company borrowed an additional sum of $700,000            from Citibank, N.A. under its existing revolving credit facility dated June 29,            2006.   The additional borrowing resulted from an increase in the            Company’s borrowing base under the Citibank credit facility from $2.6 million to            $3.3 million based upon Citibank’s periodic review of the Company’s            borrowing base.  With the additional borrowing, the Company has borrowed the full            amount of its $3.3 million borrowing base under the revolving Citibank credit facility.            Repayment of this additional sum is subject to the terms and conditions of the Citibank            credit facility. The additional amount borrowed will be used for further development of            the Company’s producing properties.    

 

| **16.** | **Sovereign Bank** |
|---------|--------------------|

 

On December 17, 2007, Citibank assigned the Company’s revolving            credit facility with Citibank to Sovereign Bank of Dallas, Texas            (“Sovereign”) as requested by the Company.

             

Under the facility as assigned to Sovereign, loans and letters of credit            will be available to the Company on a revolving basis in an amount outstanding not to            exceed the lesser of $20 million or the Company’s borrowing base in effect from            time to time. The Company’s initial borrowing base with Sovereign was set at $7.0            million, an increase from its borrowing base of $3.3 million with Citibank prior to the            assignment.

             

The Company’s initial borrowing on December 17, 2007 under its new            facility with Sovereign was approximately $4.2 million which will bear interest at a            floating rate equal to prime as published in the Wall Street Journal plus 0.25%            resulting in a current interest rate of approximately 7.5%. Interest only is payable            during the term of the loan and the principal balance of the loan is due December 31,            2010. The Sovereign facility is secured by substantially all of the Company’s            producing and non-producing oil and gas properties and pipeline and the Company’s            Methane Project assets.

             

The Company used a portion of the $4.2 million borrowed from Sovereign            to pay off the funds it previously borrowed from Citibank. The remaining $900,000            borrowed from Sovereign was used to pay bank fees and attorney fees relating to the            assignment in the amount of approximately $75,000 and the balance of approximately            $825,000 was used to pay a portion of the purchase price for equipment to be utilized            in the Methane Project currently under construction in Carter Valley, Tennessee by MCC,            the Company’s wholly-owned subsidiary.

 

**F-25**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

| **17.** | **Methane Project** |
|---------|---------------------|

 

On October 24, 2006 the Company signed a twenty-year Landfill Gas Sale            and Purchase Agreement (the “Agreement”) with BFI Waste Systems of            Tennessee, LLC (“BFI”). The Agreement was thereafter assigned to the            Company’s wholly-owned subsidiary, Manufactured Methane Corporation            (“MMC”) and provides that MMC will purchase all the naturally produced gas            stream presently being collected and flared at the municipal solid waste landfill in            Carter Valley serving the metropolitan area of Kingsport, Tennessee that is owned and            operated by BFI in Church Hill, Tennessee. BFI’s facility is located about two            miles from the Company’s existing pipeline serving Eastman Chemical Company            (“Eastman”). Contingent upon obtaining suitable financing, the Company            plans to acquire and install a proprietary combination of advanced gas treatment            technology to extract the methane component of the purchased gas stream.  Methane            is the principal component of natural gas and makes up about half of the purchased gas            stream by volume. The Company plans to construct a small diameter pipeline to deliver            the extracted methane gas to the Company’s existing pipeline for delivery to            Eastman (the “Methane Project”).

 

MCC has placed equipment orders for its first stage of process equipment            (cleanup and carbon dioxide removal) and the second stage of process equipment            (nitrogen rejection) for the Methane Project. It is anticipated that the total costs            for the Project including pipeline construction, will be approximately $4.1 million            including costs for compression and interstage controls. The costs of the Methane            Project to date have been funded primarily by (a) the money received by the Company            from Hoactzin to purchase its interest in the Ten Well Program which exceeded the            Company’s actual costs of drilling the wells in that Program by more than $1            million (b) cash flow from the Company’s operations in the amount of            approximately $1 million and (c) $825,000 of the funds the Company borrowed from its            credit facility with Sovereign Bank. The Company anticipates that most of the remaining            balance of the Methane Project costs will be paid from the Company’s cash            flow.

 

The Company anticipates that the equipment ordered by MMC will be            manufactured and delivered to allow operations to begin in mid-2008 after equipment            installation, testing, and startup procedures are begun. Commercial deliveries of gas            will begin when the equipment is installed and tested and the pipeline is constructed.            Upon commencement of operations, the methane gas produced by the project facilities            will be mixed in the Company’s pipeline and delivered and sold to Eastman            Chemical Company (“Eastman”) under the terms of the Company’s            existing natural gas purchase and sale agreement. At current gas production rates and            expected extraction efficiencies, when commercial operations of the Project begin, the            Company would expect to deliver about 418 MMBtu per day of additional gas to Eastman,            which would substantially increase the current volumes of natural gas being delivered            to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas            of $7 per MMBtu, near the average natural gas price received by the Company in 2007,            the anticipated net revenues to the Company would be approximately $800,000 per year            from the Methane Project based on anticipated volumes and expenses. The gas supply from            this project is projected to grow over the years as the underlying operating

 

**F-26**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

landfill continues to expand and generate additional naturally produced            gas, and for several years following the closing of the landfill, currently estimated            by BFI to occur between the years 2022 and 2026.

 

As part of the Methane Project agreement, the Company agreed to install            a new force-main water drainage line for Allied Waste Industries, an affiliate of BFI,            the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for            the project, reducing overall costs and avoiding environmental effects to private            landowners resulting from multiple installations of pipeline. Allied Waste will pay the            additional costs for including the water line. Construction of the gas pipeline needed            to connect the facility with the Company’s existing natural gas pipeline began in            January 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC,            requires no additional permits for the gas pipeline construction. The Company currently            anticipates that pipeline construction will be concluded approximately the same time as            equipment deliveries and installations occur or in the May to June 2008 time period,            subject to weather delays during wintertime construction.

 

On September 17, 2007, Hoactzin, simultaneously with subscribing to            participate in the Ten Well Program, pursuant to a separate agreement with the Company            was conveyed a 75% net profits interest in the Methane Project. When the Methane            Project comes online, the revenues from the Project received by Hoactzin will be            applied towards the determination of the Payout Point (as defined above) for the Ten            Well Program. When the Payout Point is reached from either the revenues from the wells            drilled in the Program or the Methane Project or a combination thereof,            Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5%            net profits interest. The Company believes that the application of revenues from the            methane project to reach the Payout Point will rapidly accelerate reaching the Payout            Point. Those excess funds provided by Hoactzin were used to pay for approximately            $1,000,000 of equipment required for the Methane Project, or about 25% of the            Project’s capital costs. The availability of the funds provided by Hoactzin            eliminated the need for the Company to borrow those funds, to have to pay interest to            any lending institution making such loans or to dedicate Company revenues or revenues            from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5%            interest in the Methane Project to Hoactzin was negotiated by the Company as a            favorable provision to the Company in the overall transaction.

 

| **18.** | **Restricted Cash** |
|---------|---------------------|

             

As security required by Tennessee oil and gas regulations, the Company            placed $120,500 in a Certificate of Deposit to cover future asset retirement            obligations for the Company’s Tennessee wells.

 

| **19.** | **Quarterly Data and Share Information                            (unaudited)** |
|---------|---------------------------------------------------------------------------------|

 

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

 

**F-27**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

**Fiscal Year Ended 2007**

             

|                                                                           | First Quarter                                                                                  | Second Quarter                                                                               | Third Quarter(a)                                                                               | Fourth Quarter(a)                                                                              |
|--------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------|
| Revenues                                                                       | **$1,772,400**                                                                                 | **$2,220,439**                                                                               | **$2,375,229**                                                                                 | **$3,000,556**                                                                                 |
| Net loss/income                                                                | **($209,165)**                                                                                 | **$**   **330,756**                                                           | **$1,580,662**                                                                                 | **$1,808,069**                                                                                 |
| Net loss/income attributable to common                            stockholders |  

                             

                             

**($209,165)** |  

                             

                             

**$330,756** |  

                             

                             

**$1,580,662** |  

                             

                             

**$1,808,069** |
| Income/loss per common share                                                   |  

**$**       **0.00**                                |  

**$**       **.01**                               |  

**$**        **0.03**                          |  

**$**         **0.03**                    |

             

**Fiscal Year Ended 2006**

             

|                                                                           | First Quarter                                                                                                            | Second Quarter                                                                                                           | Third Quarter                                                                                                            | Fourth Quarter                                                                                                           |
|--------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------|
| Revenues                                                                       | **$** **2,098,969**                                                                                                 | **$** **2,354,736**                                                                                                 | **$** **2,251,274**                                                                                                 | **$**  **2,296,702**                                                                                           |
| Net loss/income                                                                | **316,347**                                                                                                              | **720,769**                                                                                                              | **519,094**                                                                                                              | **585,154**                                                                                                              |
| Net loss/income attributable to common                            stockholders |  

                             

                             

**$**    **316,347** |  

                             

                             

**$**    **720,769** |  

                             

                             

**$**    **519,094** |  

                             

                             

**$**    **585,154** |
| Income/loss per common share                                                   |  

**$**          **0.01**                                        |  

**$**          **0.01**                                        |  

**$**          **0.01**                                        |  

**$**           **0.01**                                  |

             

(a)

The company recorded 1.1 million in deferred tax asset in the third            quarter of 2007 and 1.0 million in the fourth quarter of 2007.

             

**20.Supplemental Oil and Gas Information            (unaudited)**

             

Information with respect to the Company’s oil and gas producing            activities is presented in the following tables. Estimates of reserve quantities, as            well as future production and discounted cash flows before income taxes, were            determined by Ryder Scott Company, L.P. as of December 31, 2005, The reserves were            estimated by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.

             

**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:

             

 

**F-28**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

 

|                                           | **2007**      | 2006                                      | 2005                                                |
|------------------------------------------------|---------------|-------------------------------------------|-----------------------------------------------------|
| Property acquisitions                          |          |                                      |                                                |
| Proved                                         | **200,000**   |                                      |                                                |
| Unproved                                       |          |                                      | -                                                   |
| Less –proceeds from

Sales of properties | **-**         |  

-                                 |  

$      (2,651,770) |
| Development Cost                               | **4,990,611** | 4,172,462                                 | 402,876                                             |
|                                           | **5,190,611** | $      4,172,462 | $      (2,248,894)    |

             

**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, | **2007**              | 2006                           | 2005                           |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------|--------------------------------|--------------------------------|
| Revenues                                                                                                                                                                                              | **9,300,144**         | $  8,896,036         | $  7,076,790         |
| Production costs and taxes                                                                                                                                                                            | **(4,160,488)**       | (3,145,244)                    | (2,956,307)                    |
| Depreciation, depletion and amortization                                                                                                                                                              |  

**(834,638)** |  

(1,144,711)            |  

(902,132)              |
| Income from oil and gas producing activities                                                                                                                                                          |  

**4,305,018** |  

$  4,606,081 |  

$  3,218,351 |

             

In the presentation above, no deduction has been made for indirect costs            such as corporate overhead or interest expense. No income taxes are reflected above due            to the Company’s operating tax loss carry-forwards.

             

**Oil and Gas Reserves**

             

The following table sets forth the Company’s net proved oil and            gas reserves at December 31, 2007, 2006 and 2005 and the changes in net proved oil and            gas reserves for the years then ended. Proved reserves represent the quantities of            crude oil and natural gas which geological and engineering data demonstrate with            reasonable certainty to be recoverable in the future years from known reservoirs under            existing economic and operating conditions. Reserves are measured in barrels (bbls) in            the case of oil, and units of one thousand cubic feet (Mcf) in the case of            gas.

             

 

**F-29**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

 

|                                                                                                         | *Oil (bbls)*      | *Gas (Mcf)*                                                                                                   |
|--------------------------------------------------------------------------------------------------------------|-------------------|---------------------------------------------------------------------------------------------------------------|
| Balance, December 31, 2004                                                                                   | 1,090,000         | 7,947,000                                                                                                     |
| Revisions of previous estimates                                                                              | 175,285           | (629,633)                                                                                                     |
| Improved Recovery                                                                                            | 79,600            | -                                                                                                             |
| Purchase of Reserves in Place                                                                                |              |                                                                                                          |
| Extensions and Discoveries                                                                                   | 174,130           | -                                                                                                             |
| Production                                                                                                   | (144,552)         | (204,128)                                                                                                     |
| Sale of Reserves in Place                                                                                    | -                 | (2,350,000)                                                                                                   |
|                                                                                                         |              |                                                                                                          |
| Proved reserves at December 31, 2005                                                                         | 1,374,463         | 4,763,239                                                                                                     |
| Revisions of previous estimates                                                                              | 20,120            | (3,318,074)                                                                                                   |
| Improved recovery                                                                                            | 110,460           | -                                                                                                             |
| Purchase of Reserves in Place                                                                                |              |                                                                                                          |
| Extensions and Discoveries                                                                                   | 396,152           | -                                                                                                             |
| Production                                                                                                   | (189,189)         | (138,078)                                                                                                     |
|                                                                                                         |              |                                                                                                          |
| Sales of Reserves in Place                                                                                   | -                 | -                                                                                                             |
| Proved reserves at December 31, 2006

                                                                  | 1,712,006         | 1,307,087

                                                                                              |
|                                                                                                         |              |                                                                                                          |
| Revisions of previous estimates                                                                              | 699,578           | (45,948)

                                                                                               |
| Improved recovery                                                                                            | 19,502            | -                                                                                                             |
| Purchase of Reserves in Place                                                                                | 16,234            |                                                                                                          |
| Extensions and Discoveries                                                                                   | 13,838            | -                                                                                                             |
|                                                                                                         |              |                                                                                                          |
| Production                                                                                                   | (185,188)         | (126,746)                                                                                                     |
|                                                                                                         |              |                                                                                                          |
| Sales of Reserves in Place                                                                                   | -                 | -

                             

                             

                              |
|                                                                                                         |              |                                                                                                          |
| Proved reserves at December 31, 2007

                             

                              | 2,275,970         | 1,134,393                                                                                                     |
|                                                                                                         |              |                                                                                                          |
| Proved developed producing reserves at.

resere                                                              | 1,604,607         | 1,130,869                                                                                                     |
| December 31, 2007                                                                                            |              |                                                                                                          |
|                                                                                                         |              |                                                                                                          |
| Proved developed producing reserves at.

resere                                                              | 1,358,532         | 1,264,527                                                                                                     |
| December 31, 2006                                                                                            |              |                                                                                                          |
|                                                                                                         |  

1,091,135 |  

2,814,306                                                                                             |
| Proved developed producing reserves at.

resere                                                              | 1,091,135         | 2,814,306                                                                                                     |
| December 31, 2005                                                                                            |              |                                                                                                          |
|                                                                                                              |                   |                                                                                                               |  |  |

             

 

 

**F-30**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

 

|                                                                           |                    |                    |                    |    |    |      |    |    |      |
|--------------------------------------------------------------------------------|-------------------------|-------------------------|-------------------------|---------|---------|-----------|---------|---------|-----------|
|                                                                           |                    |                    |                    |    |    |      |    |    |      |
|                                                                           | **Year Ended 12/31/07** | **Year Ended 12/31/06** | **Year Ended 12/31/05** |
| *(amounts in thousands)*                                                       | **Oil**                 | **Gas**                 | **Total**               | **Oil** | **Gas** | **Total** | **Oil** | **Gas** | **Total** |
|                                                                           |                    |                    |                    |    |    |      |    |    |      |
| **Total**proved reserves                            year-end reserve report    | $52,117                 | $1,510                  | $53,627                 | $24,099 | $2,370  | $26,469   | $23,530 | 13,649  | $37,179   |
|                                                                           |                    |                    |                    |    |    |      |    |    |      |   |
| **Proved developed producing**reserves (PDP)                                   | $36,319                 | $1,485                  | $37,804                 | $19,335 | $2,370  | $21,705   | $18,721 | $8,048  | $26,769   |
| % of PDP reserves to total proved reserves                                     | 67%                     | 3%                      | 70%                     | 73%     | 9%      | 82%       | 50%     | 22%     | 72%       |
|                                                                           |                    |                    |                    |    |    |      |    |    |      |
| **Proved developed non-producing                            reserves**         | $441                    | $25                     | $466                    | $529    | $0      | $529      | $1,602  | $3,603  | $5,205    |
| % of PDNP and PBP reserves to total proved                            reserves | 1%                      | 0%                      | 1%                      | 2%      | 0%      | 2%        | 4%      | 10%     | 14%       |
|                                                                           |                    |                    |                    |    |    |      |    |    |      |
| **Proved undeveloped reserves**(PUD)                                           | $15,357                 | $0                      | $15,357                 | $4,235  | $0      | $4,235    | $3,207  | $1,998  | $5,205    |
| % of PUD reserves to total proved reserves                                     | 29%                     | 0%                      | 29%                     | 16%     | 0%      | 16%       | 9%      | 5%      | 14%       |
|                                                                           |                    |                    |                    |    |    |      |    |    |      |

 

 

**Standardized Measure of Discounted Future Net Cash            Flows**

             

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

             

| *(amounts in thousands)*                  |                         |
|-------------------------------------------|------------------------------|
| December 31,                              | **2007**                     | 2006 | 2005 |
|                                      |                         |   |   |
| Future cash inflows                       | **$**  **206,276** | $  107,291 | $  130,584 |
| Future production

costs and taxes        | **(76,944)**                 |  

(52,033) |  

(55,625) |
| Future development costs                  | **(10,175)**                 | (4,505) | (1,494) |
| Future income tax expenses                | **-**                        | - | - |
| Net future cash flows                     | **119,157**                  | 50,753 | 73,465 |
| Discount at 10% for

timing of cash flows |  

**(65,530)**         |  

(24,284) |  

(36,286) |
|                                           |                              |  |  |  |

             

             

 

**F-31**

 

----

**Tengasco, Inc. and Subsidiaries**

**Notes to Consolidated Financial Statements**

 

 

|  

Discounted future net cash flows from proved                            reserves |  

**$**  **53,627**                       |  

$   26,469 |  

$   37,179 |
|------------------------------------------------------------------------------------------|-----------------------------------------------------------|-----------------------------------|-----------------------------------|
|                                                                                     |                                                      |                              |                              |
| *(amounts in thousands)*                                                                 |
|                                                                                     | **2007**                                                  | 2006                              | 2005                              |   |
|                                                                                     |                                                      |                              |                              |   |
| **Balance,**beginning of                            year                                 | **$**  **26,469**                               | $  37,179               | $  26,731               |   |
| Sales, net of production costs

and taxes                                                |  

**(5,140)**                                       |  

(5,751)                   |  

(4,121)                   |   |
| Discoveries and extensions                                                               | **1,166**                                                 | 1,734                             | 453                               |   |
| Purchases of Reserves                                                                    | **568**                                                   | -                                 | -                                 |   |
| Changes in prices and

production costs                                                  |  

**16,893**                                        |  

(6,329)                   |  

13,537                    |   |
| Revisions of quantity estimates                                                          | **16,584**                                                | (1,781)                           | 4,559                             |   |
| Sale of Reserves                                                                         | **-**                                                     | -                                 | (4,856)                           |   |
| Interest factor - accretion

of discount                                                 |  

**2,647**                                         |  

3,718                     |  

2,673                     |   |
| Net change in income taxes                                                               | **-**                                                     | -                                 | -                                 |   |
| Changes in future development costs                                                      | **(5,669)**                                               | (3,010)                           | 262                               |   |
| Changes in production rates

and other                                                   |  

109                                               |  

709                       |  

(2,059)                   |   |
| **Balance,**end of                            year                                       | **$**       **53,627** | $  26,469               | $  37,179               |   |
|                                                                                          |                                                           |                                   |                                   |  |  |  |  |

             

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, 2007, 2006, and 2005 were $85.44, $56.50, and $55.81, per            barrel of oil and $7.21, $8.33 and $11.31 per MCF of gas, respectively. No deduction            has been made for depreciation, depletion or any indirect costs such as general            corporate overhead or interest expense.

             

Operating costs and production taxes are estimated based on current            costs with respect to producing properties. Future development costs are based on the            best estimate of such costs assuming current economic and operating            conditions.

             

Income tax expense is computed based on applying the appropriate            statutory tax rate to the excess of future cash inflows less future production and            development costs over the current tax basis of the properties involved, less            applicable net operating loss carry-forwards, for both regular and alternative minimum            tax. For the years ended December 31, 2007, 2006 and 2005 the Company’s available            net operating loss carry forwards offset all tax effects applicable to the discounted            future net cash flows.

The future net revenue information assumes no escalation of costs or            prices, except for gas sales made under terms of contracts which include fixed and            determinable escalation. Future costs and prices could significantly vary from current            amounts and, accordingly, revisions in the future could be significant.

             

 

**F-32**