Edgar Filing: TENGASCO INC

tenkmarch30.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

REPORT ON FORM 10-K

(Mark one)

[X} Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2009 or

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

Commission File No. 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.)

11121 Kingston Pike Suite, E	Knoxville, TN 37934
(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 [ ] [X] No

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 [ ] [X] No

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

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files [ ] Yes [ ] No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 [ ] Accelerated Filer [ ] Non-accelerated Filer [ ] Smaller Reporting Company [ ]

(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 [ ] No [X]

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 was approximately $21 million (June 30, 2009 closing price $0.56)

The number of shares outstanding of the registrant’s $.001 par value common stock as of the close of business on (March 12, 2010) was 59,760,661

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 21, 2010, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the close of the registrant’s fiscal year.

Table of Contents

PART I			Page
	Item 1.	Business……………………………………………………………..	5
	Item 1A.	Risk Factors…………………………………………………………	21
	Item 1B.	Unresolved Staff Comments….…………..…………………….......	31
	Item 2.	Properties……………………………………………………………	31
	Item 3.	Legal Proceedings……………………………………..……....…....	39
	Item 4.	(Removed and Reserved)…………………………………………...	39

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities………………...	39
	Item 6.	Selected Financial Data…………………………………………….	41
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation……………………………………….….	42
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk…….	49
	Item 8.	Financial Statements and Supplementary Data…….……………...	51
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure………………………………………….	51
	Item 9A(T).	Controls and Procedures………………………………………….	51
	Item 9B.	Other Information………..………………………………………..	52

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance………..	53
	Item 11.	Executive Compensation………………………………………….	53
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters….……………………………..	53
	Item 13.	Certain Relationships and Related Transactions, and Director Independence………..…………………………………………….	54
	Item 14.	Principal Accounting Fees and Service…………………………...	54

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” or any similar word or phrase regarding the future. Forward-looking statements also include statements regarding revenue margins, expenses, and earnings analysis for 2009 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 statement. 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, which in the past year have been extremely volatile, 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.

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this document:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

BOE. One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 thousand cubic feet of gas to 1 barrel of oil.

BOPD. Barrels of oil per day.

Btu. British thermal unit. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii)

through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities.

Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date,

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Gas. Natural gas.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of gas.

Mcfd. One thousand cubic feet of gas per day

MMcfe. One million cubic feet of gas equivalent.

MMBOE. One million BOE.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of gas.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Operator. The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Play. A geographic area with hydrocarbon potential.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved reserve additions. The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known

accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reserve additions. Changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery and other additions and purchases of reserves in-place.

Reserve life. A measure of the productive life of an oil and gas property or a group of properties, expressed in years.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

SWD. Salt water disposal well

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

References herein to the “Company”, “we”, “us” and “our” mean Tengasco, Inc.

PART I

ITEM 1. BUSINESS.

History of the Company

The Company was initially organized in Utah in 1916 under a name 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 exploration for and production of oil and natural gas. The Company’s primary area of oil exploration and production is in Kansas. The Company’s primary area of gas exploration and production is the Swan Creek field in Tennessee.

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’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) owns and operates 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.

The Company also has 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. (See 4. Management Agreement with Hoactzin on page 12) 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 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

The Kansas Properties presently include 184 producing oil wells in central Kansas. Our management and staff have a great deal of Kansas exploration and production experience. We have onsite production management and field personnel working in Kansas.

On July 2, 2008, the Company acquired 19 leases encompassing approximately 1,577 acres and 41 oil wells producing approximately 80 barrels of oil per day in Rooks County, Kansas together with salt water disposal wells and related equipment from Black Diamond Oil, Inc. for $5.35 million. The leases acquired are in the Company’s core area in central Kansas and are a part of the larger Riffe Field. Polymer treatments on several existing wells resulted in an increase in production of the acquired wells to 147 BOPD by the end of 2008. Total production during the initial six month ownership period was 22 MBbls, an average of 122 BOPD. In 2009, despite very little freshly deployed capital, these wells averaged 111 BOPD.

In 2009, the decrease in oil prices, particularly in the first 6 months of the year, prevented the Company from having sufficient cash flow to remain as active in drilling new wells and performing polymer treatments as we had been in prior years. We had no capital spending until late 2009 and only drilled one salt water disposal well for the 2008 Albers discovery wells which produced 21 MBbls in 2009. We also performed 2 polymer jobs late in 2009 which added 2.9 MBbls to our production total.

In 2009, the Company continued to try to acquire key acreage and analyze seismic data to aid its exploration and development program. While the Company intends in 2010 to return to a more active drilling and workover program, the level of activity will be driven by cash flow. Those expectations can be tempered with a change in oil prices like we endured in late 2008 and early 2009. At the time of this writing, prices and our derivative position will allow a more active plan for 2010.

A. Kansas Ten Well Drilling Program

On September 17, 2007, the Company entered into a ten well drilling program with Hoactzin, consisting of 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 paid the Company $400,000 for each producing well and $250,000 for each per dry hole. The terms of the Program also provided that Hoactzin would receive all the working interest in the producing wells, and would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses, referred to as a management fee. The fee paid to the Company by Hoactzin will increase to 85% working interest when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”).

Nine of the ten wells in the program were completed as oil producers and are currently producing approximately 61 barrels per day in total. Hoactzin paid a total of $3.85 million (the “Purchase Price”) for its interest in the Program resulting in the Payout Point being determined as $5.2 million. The Purchase Price paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling cost of approximately $2.6 million for the ten wells by more than $1 million.

In 2009, the wells from the Program produced 22 MBbls of which 14 MBbls were net to Hoactzin. As of December 31, 2009, net revenues received by Hoactzin from the Program total $2.5 million which leaves a balance of $2.7 million until the Payout Point is reached.

Although production level of the Program wells will decline over time in accordance with expected decline curves, based on the drilling results of the Program wells to date and the current price of oil, the Program wells are expected to reach the Payout Point in approximately four years from first production. However, under the terms of the agreement reaching the Payout Point could be accelerated by applying 75% of the net proceeds Hoactzin receives from the methane extraction project developed by MMC at the Carter Valley, Tennessee landfill (the “Methane Project”), toward reaching the Payout Point. (The Methane Project is discussed in greater detail below.) The Methane Project net proceeds when applied would result in the Payout Point being achieved sooner than the estimated four year period based solely upon revenues from the Program wells.

On September 17, 2007, the Company entered into another agreement with Hoactzin providing that if the Program and the Methane Project in combination failed to return net revenues to Hoactzin equal to 25% of the Purchase Price by December 31, 2009, then Hoactzin had an option to exchange up to 20% of its net profits interest in the Methane Project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the Purchase Price less the net proceeds received at the time of any exchange. The conversion option would be set at issuance of the preferred stock at the then twenty business day trailing average closing price of Company stock on the NYSE Amex. This option could not have occurred at year-end 2009 because approximately 50% of the Purchase Price was returned to Hoactzin from revenues from the wells in the Program by the end of 2008. Hoactzin has a similar option each year after 2010 in which Hoactzin’s then-unrecovered Purchase Price at the beginning of the year is not reduced 20% further by the end of that year, using the same conversion option calculation. The Company, however, may in any year make cash payment from any source in the amount required to prevent such an exchange option for preferred stock from arising. In addition, the conversion right is limited to a conversion of no more than 19% in the aggregate of the outstanding common shares of the Company. In the event Hoactzin’s 75% net profits interest in the Methane Project were fully exchanged for preferred stock Hoactzin would retain no net profits interest in the Methane Project after the full exchange.

Under this exchange agreement, if no proceeds at all were received by Hoactzin through 2009 or in a later year (i.e. a worst-case scenario already impossible in view of the success of the Program), then Hoactzin would have an option to exchange 20% of its interest in the Methane Project beginning in 2011 and each year thereafter for preferred stock convertible at the trailing average price before each year’s issuance of the preferred. The number of common shares into which the preferred stock could be converted cannot be currently calculated, because the conversion price is based on a future stock price.

However, as stated, net revenues received by Hoactzin from the wells in the Program through December 31, 2009 totaled $2.5 million leaving a balance of $1.3 million to reach the point at which no preferred stock can be issued to Hoactzin thus making it highly unlikely that any preferred stock will ever be issued to Hoactzin. The Company notes that with the demonstrated successful results of production from the wells in the Program that the payout of 25% of the Purchase Price was reached by year-end 2008, a full year before the December 31, 2009 required date, therefore no requirement to issue preferred

stock will arise in 2010. The Company further anticipates that at current prices of about $70.00 per barrel of oil and $6.00 per Mcf of gas, and at currently expected sales levels of methane gas from the Methane Project that the balance of the unrecovered Purchase Price by Hoactzin may be fully recovered by Hoactzin by year-end 2011. If this occurs the possibility of being required to issue any preferred ceases to exist. If it does not occur, the Company believes it is highly unlikely that any obligation to issue preferred stock will arise under the terms of this agreement at any time in the future, because the production results in any future year should readily satisfy the small production levels required to prevent an optional preferred stock issuance from arising in any year.

B. Kansas Production

The Company’s gross oil production in Kansas decreased in 2009 from 2008 levels. In 2009, the Company produced 217 MBbls in Kansas compared to 232 MBbls in 2008. The two wells that were polymered in 2009 produced 2.9 MBbl and the one new well drilled in 2009 was a salt water disposal well (SWD) for the Albers lease.

Capital projects for the Company are funded by cash flow and in 2009 the Company had reduced cash flow, especially in the first 9 months of the year. We plan to be more active in 2010 as current oil prices have increased. However, decreases in future oil prices may cause the Company to reduce capital spending. In July 2009 the Company hedged a specified number of barrels of oil that currently constitutes about two-thirds of the Company’s daily production to minimize this effect.

2. The Tennessee Properties

In the early 1980’s Amoco Production Company owned numerous 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. Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the Knox Formation. 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 to deliver gas from the Swan Creek Field to the closest market. In July 1995, the Company acquired the Swan Creek leases and began development of the field.

A. Swan Creek Pipeline Facilities

The Company’s completed pipeline system is owned and operated by Tengasco Pipeline Corporation (“TPC”), the Company’s wholly-owned subsidiary and extends 65 miles from the Swan Creek Field to a meter station at Eastman Chemical Company’s (“Eastman”) plant in Kingsport, Tennessee. The pipeline system was built for a total cost of $16.4 million.

B. Swan Creek Production and Development

The Company has concluded based on the results of previously drilled wells and seismic data that drilling new gas wells in the Swan Creek Field would not achieve any significant increase in daily gas production totals from the Field. Current wells in production in the Swan Creek Field would be capable of and would likely produce all the remaining reserves in that Field. As a result, the Company has not drilled any new gas wells in the Swan Creek Field since 2004.

Because no drilling for natural gas in the Knox formation 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 16 wells 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 2008 to 2009 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 2008-2009 period.

During 2009, the Company had 17 producing gas wells and 4 producing oil wells in the Swan Creek Field. Gas sales from the Swan Creek Field during 2009 averaged 124 Mcfd compared to 215 Mcfd in 2008.

In January 2008, the Company signed a farmout agreement with Jacobs Energy, L.L.C. (“Jacobs Energy”) of Glasgow, Kentucky related to development of the Company’s 1,405 leased acres in Hancock County, Tennessee and an additional area of approximately 20,000 surrounding acres constituting an area of mutual interest (“AMI”) for the purpose of exploring the rim of the Swan Creek anticline for Devonian shale gas production. The agreement was in the form of a “drill to earn” relationship whereby Jacobs Energy was to establish commercial production at its sole cost from the first two test wells in order to earn a 50% interest in the two test wells and right to participate on a fifty-fifty basis in all remaining wells that may be drilled in the AMI. The Company had no obligation for any of the costs of the two test wells. The Company would bear 50% of the costs of any new wells drilled in the future within the AMI. In the event commercial production was not established, Jacobs Energy would not earn any interest in the test wells nor in the AMI and the farmout agreement would terminate.

By the end of 2008, Jacobs Energy had re-completed the Ted Hall No. 1 well, which constituted the completion of the first of the two test wells under the farmout agreement. On July 8, 2009, the Company terminated the farmout agreement with Jacobs Energy under its terms. The Company determined that the first of the two test wells contemplated by the agreement was not properly completed and evaluated for nitrogen content. It was never determined how much of the nitrogen was occurring naturally, and how much was a result of the completion management. Second, the Company determined that Jacobs Energy had failed to perform in a commercially timely manner by not having yet drilled the second test well. Jacobs Energy had stated to the Company in early July 2009 that for the foreseeable future it would not be economically feasible for Jacobs Energy to drill the second test well based on Jacobs’s assessment of the current state of the financial markets. Based on that statement, together with the removal of Jacobs’ equipment from the first well, the Company determined that Jacobs had abandoned its obligations under the agreement, constituting a separate basis for the Company’s termination of the agreement. Because the agreement was terminated, no assignments of any interest in any properties were made, and no such assignments are due to be conveyed to Jacobs Energy,

The Company continues to seek development of these properties with other industry partners as it remains possible that when more than one well is drilled, it may be economically feasible to treat (if necessary) the produced gas as required, and to construct gathering facilities necessary to connect to the Company’s pipeline to bring the gas to market. To date no industry partners have been found by the Company to further explore these properties and no assurances can be made that such a partner can be found or that an agreement may be reached with such partner on terms acceptable to the Company.

3. 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 (“Allied”). In 2008, Allied merged into Republic Services, Inc. (“Republic”). The Company assigned its interest in the Agreement to MMC and provides that MMC will purchase the entire naturally produced gas stream being collected at the Carter Valley municipal solid waste landfill owned and operated by Republic in Church Hill, Tennessee serving the metropolitan area of Kingsport, Tennessee. Republic’s facility is located about two miles from the Company’s pipeline. The Company installed 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 raw gas stream by volume. The Company has constructed a pipeline to deliver the extracted methane gas to the Company’s existing pipeline (the “Methane Project”).

The total cost for the Methane Project, including pipeline construction, was approximately $4.5 million. The costs of the Methane Project were 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; and (c) $0.8 million of the funds the Company borrowed under its credit facility with Sovereign Bank of Dallas, Texas (“Sovereign Bank”). Methane gas produced by the project facilities was initially mixed in the Company’s pipeline and delivered and sold to Eastman under the terms of the Company’s natural gas purchase and sale agreement with Eastman. At current gas production rates in the landfill itself and expected extraction efficiencies, the Company estimates it will be able to produce and deliver about 400 Mcfd of methane sales gas. The gas supply from this landfill 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, estimated by Republic to occur between the years 2022 and 2029. Gas production will continue in commercial quantities up to 15 years after closure of the landfill.

As part of the Methane Project agreement, the Company agreed to install a new force-main water drainage line for Republic, 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. Republic paid the additional material costs for including the water line of approximately $0.7 million. As a certificated utility, the Company’s pipeline subsidiary, TPC, required no additional permits for the gas pipeline construction.

Initial test volumes of methane were produced in late December 2008. During the first two months of 2009, Eastman was reviewing its current air quality permits with regard to MMC’s methane production and deliveries did not occur during that review.

monitoring rules applicable to Eastman’s large boilers during the annual “smog season” beginning May 1 of each year. Although Eastman had begun seeking this approval in February, 2009, with the assistance of the Air Quality Department of the Tennessee Department of Environment and Conservation, the EPA had not acted by May 1. Eastman furnished to the EPA information provided by MMC that establishes that the methane gas stream is better fuel under the rule standards than even “natural” gas, which is technically defined in the smog season rules to include gas being “found in geologic formations beneath the earth’s surface”. Methane sales to Eastman were intended to resume upon EPA’s formal approval of Eastman’s petition or expansion of the regulatory definition, or both. However, as of December 31, 2009 neither of these actions has been taken by EPA, despite the existence of EPA’s own established agency initiative, the Landfill Methane Outreach Program, which is intended to encourage beneficial use of the methane component of raw landfill gas. Because approval was not received, MMC was forced to seek alternative markets for the methane gas stream.

The Company concluded an agreement for sale of the methane gas to Hawkins County Gas Utility, a local utility commencing August 1, 2009 on a month to month basis until either sales to Eastman may resume or other customers were located by the Company.

Effective September 1, 2009 the Company began sales of its Swan Creek gas production to Hawkins County Gas Utility District, because the physical mixing of Swan Creek natural gas with MMC’s methane gas caused Eastman to suspend deliveries of both categories of gas as mixed.

On August 27, 2009, the Company entered into a five-year fixed price gas sales contract with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of landfill gas produced by MMC at the Carter Valley Landfill. The agreement provides for the sale of up to 600 MMBtu per day. The contract is effective beginning with September 2009 gas production and ends July 31, 2014. The agreed contract price of over $6 per MMBtu was a premium to the then current five-year strip price for natural gas on the NYMEX futures market.

MMC’s plant is capable of producing a daily average of about 400 Mcfd of methane from the Carter Valley landfill at current raw gas volumes. However, daily production during September and October 2009 at MMC’s facility was intermittent due to a combination of temporary factors. Average daily production for September and October 2009 was 248 Mcfd on the twenty days the plant was in production. In November 2009, MMC’s average daily gas production on producing days was 288 Mcfd of sales methane and in December 2009, this amount was 293 Mcfd of sales methane.

and actual costs of drilling the ten wells in the Program. Those excess funds provided by Hoactzin were used to pay for approximately $1 million of equipment required for the Methane Project, or about 22% 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

The Company entered into a Management Agreement with Hoactzin on December 17, 2007. On that same date, the Company 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 interest 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 agreed that it will reimburse the Company for 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 granted to the Company an option to participate in up to a 15% working interest for a corresponding price of up to 15% of the actual project costs, in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. During 2009, the Company participated in an unsuccessful workover on West Delta 62 and spent $0.2 million or 15% of the total workover cost. The Company was able to recoup approximately one third of the cost prior to the well ceasing production. The Company did not participate in any additional projects and will not consider participation in any future projects unless and until gas prices increase. The term of the Management Agreement is the earlier of the period ending with the date Hoactzin conveys its interest in its managed properties or 5 years from the date of the agreement.

5. Other Areas of Development

The Company is continuing to review and analyze potential acquisitions of additional existing oil and gas production in areas of Kansas, Oklahoma, and Texas. Whether the Company will proceed with any such acquisition it deems appropriate will be dependent on a number of factors, including available financing, oil prices, etc. Current economic conditions, including any sharp decline in oil prices, will certainly have an adverse impact on the Company’s ability to acquire additional properties. Accordingly, there is no assurance that a suitable property will become available or even if such property becomes available that terms will be established leading to a completion of such a purchase.

The Company has evaluated other geological structures in the East Tennessee area that are similar to the Swan Creek Field. 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. 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. The principal markets for the Company’s natural gas and methane production are local utilities, private industry end-users, and 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, Hawkins County Gas Utility, Eastman and BAE in Sullivan County, as well as other industrial customers in the Kingsport area. The Company has acquired all necessary regulatory approvals and necessary property rights for the pipeline system. The Company’s pipeline can provide transportation service not only for gas produced from the Company’s wells, but also 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.

At present, crude oil produced by the Company in Kansas is sold at or near the wells to Coffeyville Resources Refining and Marketing; LLC (“Coffeyville Refining”) in Kansas City, Kansas. Coffeyville Refining is solely responsible for transportation to its refinery 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 purchases 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 by 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 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.

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 process 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 and the Methane Project principally gas marketing companies, utility districts, and 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

None.

Need For Governmental Approval of Principal Products or Services

None of the principal products offered by the Company require governmental approval, although permits are required for drilling oil or gas wells. In addition the transportation service offered by TPC is subject to regulation by the Tennessee Regulatory Authority to the extent of certain construction, safety, tariff rates and charges, and nondiscrimination requirements under state law. These requirements are typical of those imposed on regulated common carriers or utilities in the State of Tennessee 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 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 in effect.

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

The Company’s exploration, production and marketing operations are regulated extensively at the federal, state and local levels. The Company has made and will continue to make expenditures in its efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell. In addition, at the federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

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

Research and Development

None.

Number of Total Employees and Number of Full-Time Employees

The Company presently has 29 full time employees and no part-time employees.

Executive Officers of the Registrant

Identification of Executive Officers

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

Name	Positions Held	Date of Initial Election of Designation

Jeffrey R. Bailey	Chief Executive Officer1	6/17/2002

Charles Patrick McInturff	Vice-President	12/18/2007

Cary V. Sorensen	Vice-President; General Counsel; Secretary	7/09/1999

Michael J. Rugen	Chief Financial Officer	9/28/2009

Business Experience2

Charles Patrick McInturff is 57 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 Engineering from 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 workovers 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 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 workovers, pressure-transient tests and completions both onshore and offshore.

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 2010 Annual Meeting of Stockholders.

During that time period he also worked for Global Natural Resources from 1983 to 1986 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 was appointed to serve as Vice-President of the Company.

Cary V. Sorensen is 61 years old. He is a 1976 graduate of the University of Texas School of Law and has undergraduate and graduate degrees from 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 oil and gas litigation department of a Fortune 100 energy corporation in Houston 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.

Michael J. Rugen is 49 years old and was named Tengasco Chief Financial Officer in September 2009. He is a certified public accountant (Texas) with over 27 years of experience in exploration and production and oilfield service. Prior to joining Tengasco, Mr. Rugen spent 2 years as Vice President of Accounting and Finance for Nighthawk Oilfield Services. From 2001 to June 2007, he was a Manager/Sr. Manager with UHY Advisors, primarily responsible for managing internal audit and Sarbanes-Oxley 404 engagements for various oil and gas clients. In 1999 and 2000, Mr. Rugen provided finance and accounting consulting services with Jefferson Wells International. From 1982 to 1998, Mr. Rugen held various accounting and management positions at BHP Petroleum, with accounting responsibilities for onshore and offshore US operations as well as operations in Trinidad and Boliva. Mr. Rugen earned a Bachelor of Science in Accounting in 1982 from Indiana University.

Code of Ethics

The Company’s Board of Directors has adopted a Code of Ethics that applies to the Company’s financial officers and executives officers, including its Chief Executive Officer 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 Code of Ethics can be obtained free of charge by writing to Cary V. Sorensen, Secretary, Tengasco, Inc., 11121 Kingston Pike, Suite E, Knoxville, TN 37934.

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 Fifty 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 website 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 that site is http://www.sec.gov.

The Company’s website is located at http://www.tengasco.com. On the home page of the website, you may access, free of charge, the Company’s Annual Report on Form 10-K. Under the Investor Information /SEC filings tab you will find the 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 the 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 exhaustive and you are encouraged to perform your own investigation with respect to the Company and its business. You should also read the other information included in this Form 10-K, including the financial statements and related notes.

The Company’s indebtedness, the current global recession, and disruption in the domestic and global financial markets could have an adverse effect on the Company’s operating results and financial condition.

As of December 31, 2009, the outstanding principal amount of the Company’s indebtedness to Sovereign Bank was approximately $9.9 million. The level of indebtedness, coupled with the widely reported domestic and global recession, the associated low levels of energy prices, and the unprecedented levels of disruption and continuing relative illiquidity in the credit markets may, if continued for an extended period, have several important and adverse consequences on the Company’s business and operations. For example, any one or more of these factors could (i) make it difficult for the Company to service or refinance its existing indebtedness; (ii) increase the Company’s vulnerability to additional adverse changes in economic and industry conditions; (iii) require the Company to dedicate a substantial portion or all of its cash flow from operations and proceeds of any debt or equity issuances or asset sales to pay or provide for its indebtedness; (iv) limit the Company’s ability to respond to changes in our businesses and the markets in which we operate; (v) place the Company at a disadvantage to our competitors that are not as highly leveraged; or (vi) limit the Company’s ability to borrow money or raise equity to fund our working capital, capital expenditures, acquisitions, debt service requirements, investments, general corporate activity or other financing needs. The Company continues to closely monitor the recent disruption in the global financial and credit markets, as well as the recent significant decline in the market prices for oil and natural gas. As these events unfold, the Company will continue to evaluate and respond to any impact on Company operations. The Company has and will continue to adjust and reduce its drilling plans and capital expenditures as necessary. However, externally financing in the capital markets is currently not readily available, and without adequate capital resources, the Company’s drilling and other activities may be limited and the Company’s business, financial condition and results of operations may suffer. Additionally, in light of the current credit markets and the pricing for oil and natural gas, the Company’s ability to enter into future beneficial relationships with third parties for exploration and production activities may be limited, and as a result, may have an adverse effect on current operational strategy and related business initiatives.

As of September 30, 2009, the Company was out of compliance on the Leverage Ratio and Interest Coverage Ratio covenants under the Sovereign credit facility. The Company was in compliance with the remaining financial covenants under the credit facility. The noncompliance occurred primarily as a result of the low commodity prices in the last quarter of 2008 and first and second quarters of 2009 that are included in the covenant compliance calculations. The Company has received a waiver from Sovereign Bank for noncompliance of these covenants for the quarter ended September 30, 2009. There can be no assurances that Sovereign Bank will waive noncompliance of covenants should future instances occur.

Agreements Governing the Company’s Indebtedness may Limit the Company’s Ability to Execute Capital Spending or to Respond to Other Initiatives or Opportunities as they May Arise.

Because the availability of borrowings by the Company under the terms of the Company’s amended and restated credit facility with Sovereign Bank is subject to an upper limit of the borrowing base as determined by the lender’s calculated estimated future cash flows from the Company’s oil and natural gas reserves, the Company expects any sharp decline in the pricing for these commodities, if continued for any extended period, would very likely result in a reduction in the Company’s borrowing base. A reduction in the Company’s borrowing base could be significant and as a result, would not only reduce the capital available to the Company but may also require repayment of principal to the lender under the terms of the facility. Additionally, the terms of the Company’s amended and restated credit facility with Sovereign bank restrict the Company’s ability to incur additional debt. The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, and dividends, voluntary redemptions of debt, investments, and asset sales. In addition, the credit facility requires that the Company maintain compliance with certain financial tests and financial covenants. If future debt financing is not available to the Company when required as a result of limited access to the credit markets or otherwise, or is not available on acceptable terms, the Company may be unable to invest needed capital for drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt. In addition, the Company may be forced to sell some of the Company’s assets on an untimely basis or under unfavorable terms. Any of these results could have a material adverse effect on the Company’s operating results and financial conditions.

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, as specified in the credit facility, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves under the parameters established by the lender 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 lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s 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, the Company could 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 level, could cause the Company to default under its revolving credit facility with Sovereign Bank.

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 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 the Company’s 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.

Declines in Oil or Gas Prices Have and Will Materially Adversely Affect the Company’s Revenues.

The Company’s financial condition and results of operations 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. As seen in 2008 and 2009 prices for oil and natural gas are subject to extreme fluctuations in response to 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 speculating activities in the commodities markets and the overall economic environment. For example, during 2008, the price for oil was extremely volatile. In July 2008, the price of oil which had reached a record high of $147 per barrel had declined to approximately $35 per barrel by December 2008 and increased to $74 per barrel by December 2009. The Company’s operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect the Company’s revenues from its drilling operations. Further, drilling of new wells, development of the Company’s leases and acquisitions of new properties are also adversely affected and limited. As a result, the Company’s potential revenues from operations as well as the Company’s proved reserves may substantially decrease from levels achieved during the period when oil prices were much higher. There can be no assurances as to the future prices of oil or gas. 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.

Risk 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 and other 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 has a History of Significant Losses.

During the early stages of the development of its oil and gas business the Company had a history of significant losses from operations, in particular its development of the Swan Creek Field, and has an accumulated deficit of $28.5 million as of December 31, 2009. 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 was profitable in 2006 and 2007. In 2008, the Company had an operating profit before ceiling test write down of $4.8 million, but due to non-cash ceiling write-down limitation of $11.6 million ($7.7 million net of tax effects), the Company recorded a net income of $0.2 million. The Company recorded a net loss of $2.0 million in 2009. In the event the Company experiences losses in the future, those losses may curtail the Company’s development and operating activities.

The Company’s Oil and Gas Operations Involve Substantial Cost and are Subject to Various Economic Risks.

The Company’s oil and gas operations are subject to the economic risks typically associated with exploration, development, and production activities, including the necessity of making significant expenditures to locate or acquire new producing properties or to drill exploratory and developmental wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations, and accidents may cause the Company’s exploration, development, and production activities to be unsuccessful. This could result in a total loss of the Company’s investment in such well(s) or property. In addition, the cost of drilling, completing and operating wells is often uncertain.

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 either 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 properties 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. Any decline in oil prices and any prolonged period of lower prices will adversely impact the Company’s future reserves since the Company is less likely to acquire additional producing properties during such periods. The lower oil prices have a chilling effect on new drilling and development as such activities become far less likely to be profitable. Thus, any acquisition of new properties poses a greater risk to the Company’s financial conditions as such acquisitions may be commercially unreasonable.

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

The ultimate costs 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 is particularly so if the price of oil declines sharply as it did during the period from mid-2008 through January 2009. 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 business. Any such sale would result in all categories of those proved oil or gas reserves that were sold no longer being reported by the Company.

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 cost of natural gas and crude oil properties exceeds the ceiling limit, the Company must charge the amount of the excess, net of any tax effects, to earnings. 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 a 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. In 2008, the Company did incur a ceiling limitation write-down net of tax effects in the amount of $7.7 million due to the dramatically lower year-end oil prices in 2008 compared to 2007 and the resulting significant downward adjustment of the Company’s estimated proved reserves. The effect of the ceiling writedown resulted in the Company recording net income of $0.2 million in 2008. The Company did not incur a writedown in 2009 or in 2007.

Use of the Company’s Net Operating Loss Carryforwards May Be Limited.

At December 31, 2009, 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 appropriate 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 ASC 740, Income Taxes. 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 many not be able to utilize some or all of the remaining carry forwards, 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 write downs or reversals, if they occur, may be material and substantially adverse.

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 when oil prices have risen and as a result the demand for rigs and equipment when 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 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.

The Company 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.

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 cost or delays in receiving appropriate authorizations.

Insurance Does Not Cover All Risks.

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, 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 Cost 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, constructions 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. This risk could result in 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 nay 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.

The Company Faces Significant Competition with Respect to Acquisitions or Personnel.

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

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.

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 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.

The Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and listing requirements subsequently adopted by the NYSE Amex 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.

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. (“Dolphin”) which is the Company’s largest shareholder. At December 31, 2009, 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 100,000 shares of common stock. His ownership and voting control over approximately 35.6% 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.

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

As of March 12, 2010 the Company had 59,760,661 shares of common stock outstanding of which 21,667,282 shares were held by affiliates. In addition, options to purchase 3,121,000 shares of unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan of which options to purchase 2,561,000 shares were vested at March 12, 2010.

On February 8, 2010, the Company issued 100,000 options to directors, which vested immediately. In addition, 80,000 of the 400,000 options issued to Mr. McInturff on February 1, 2008 also vested.

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.

Future Issuance of Additional Shares of the Company’s Common Stock Could Cause Dilution of Ownership Interest and Adversely Affect Stock Price.

The Company may in the future issue previously authorized and unissued securities, resulting in the dilution of the ownership interest 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 60 million shares have been issued. The potential issuance of the approximately 40 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 raising capital or other business purposes. Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of the Company’s common stock.

The Company May Issue Shares of Preferred Stock with Greater Rights than Common Stock.

Subject to the rules of the NYSE Amex, 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

None.

ITEM 2. PROPERTIES.

Property Location, Facilities, Size and Nature of Ownership.

General

The Company leases its principal executive offices, consisting of approximately 6,134 square feet located at 11121 Kingston Pike, Suite E, Knoxville, Tennessee at a rental of $7,284 per month and an office in Hays, Kansas at a rental of $750.00 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 approximately $4,000 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. As of December 31, 2009 the Company does not have a production interest in Texas and Louisiana.

Kansas Properties

The Kansas Properties as of December 31, 2009 contained 150 leases totaling approximately 22,400 gross acres in the vicinity of Hays, Kansas. The decrease in the total volume of acreage of the Company’s Kansas Properties from 30,251 acres at the end of 2008 is primarily due to the Company’s evaluation and release of acreage deemed uneconomical. In 2009, the Company continued to focus on retaining properties with geologic value. Many of these leases are still in effect because they are being held by production. These leases provide for a 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.

During 2009, the Company drilled 1 gross well, the Albers #2 SWD, in which the Company has a 100% working interest.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. 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, 2009:

Kansas accounted for 91% of the Company’s revenue (i.e. $8.9 million of $9.7 million) and 92% of the Company’s total production.

The map below indicates the location of the 10 counties in Kansas in which the Company had production as of December 31, 2009.

Tennessee Properties

The Company’s Swan Creek leases are on approximately 8,300 gross acres in Hancock and Claiborne Counties in Tennessee. At this time all of the Company’s Tennessee production is from Hancock County.

Reserve and Production Summary

The following tables indicate the county breakdown of 2009 production and reserve values as of December 31, 2009. From a review of the tables below, it is apparent that none of the Company’s leases on a standalone basis are significant, but must all be viewed as a whole to appreciate their significance to the company’s operations.

Production by Area

Area	Gross Production MBOE	Average Net Revenue Interest	Percentage of Total Oil Production
Rooks County, KS	136.8	0.760244	58%
Trego County, KS	28.0	0.820411	12%
Ellis County, KS	12.3	0.820133	5%
Graham County, KS	9.0	0.870513	4%
Russell County, KS	8.1	0.848400	3%
Barton County, KS	7.0	0.814310	3%
Pawnee County, KS	6.0	0.765704	3%
Rush County, KS	4.4	0.845971	2%
Osborne County, KS	2.9	0.626262	1%
Stafford County, KS	2.2	0.827089	1%
Total KS	216.7		92%
Hancock County, TN	18.7	0.728298	8%
Total	235.4		100%

Discounted Reserve Value by Area (in thousands)

Area	Proved Developed	Proved Undeveloped	Proved Reserves	% of Total
Rooks County, KS	$12,654	$4,220	$16,874	60%
Trego County, KS	1,862	1,780	3,642	13%
Ellis County, KS	1,877	-	1,877	7%
Barton County, KS	822	635	1,457	5%
Graham County, KS	1,076	332	1,408	5%
Rush County, KS	646	-	646	2%
Stafford County, KS	410	123	533	2%
Russell County, KS	418	-	418	2%
Pawnee County, KS	292	118	410	1%
Osborne County, KS	155	95	250	1%
Total KS	20,212	7,303	27,515	98%
Hancock County, TN	672	-	672	2%
Total	$20,884	$7,303	$28,187	100%

Reserve Analyses

The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2009 and 2008, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in following tables. All of the Company’s reserves were located in the United States. These estimates were prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Dallas, 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 provided to them by the Company. In accordance with SEC regulations, no price or cost escalation or reduction was considered.

Total Proved Reserves as of December 31, 2009

	Producing	Non Producing	Undeveloped	Total
Natural gas (MMcf)	115.9	-	-	115.9
Oil (MBbls)	1,340.4	238.4	694.4	2,273.2
Total proved reserves (MBOE)	1,359.7	238.4	694.4	2,292.5
Standardized measure of discounted future net cash flow (in thousands)	$15,699	$5,185	$7,303	$28,187

Total Proved Reserves as of December 31, 2008

	Producing	Non-producing	Undeveloped	Total
Natural gas (MMcf)	907.3	2.9	-	910.2
Oil (MBbl)	1,240.0	7.7	-	1,247.7
Total proved reserves (MBOE)	1,391.2	8.2	-	1,399.4
Standardized measure of discounted future net cash flow (in thousands)	$10,134	$159	-	$10,293

In December 2008, the SEC adopted new rules related to “Modernization of Oil and Gas Reporting” which the Company adopted for the year ended December 31, 2009. Per this rule, the Company’s proved reserves as of December 31, 2009 are measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2009. The Company’s proved reserves as of December 31, 2008 were measured by using prices as of December 31, 2008. Under the SEC’s final rule, prior period reserves were not restated. These respective 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 oil and natural gas prices after basis adjustments used in our December 31, 2009 reserve valuation were $53.81 per Bbl and $4.61 per Mcf. The oil and natural gas prices after basis adjustments used in our December 31, 2008 reserve valuation were $33.96 per Bbl and $7.76 per Mcf. The $19.85 per Bbl increase in oil price was the primary factor in the increased 2009 reserve volumes and values as compared to 2008 levels. (Refer to Note 23, Supplemental Oil and Gas Information, Standardized Measure of Discounted Future Net Cash Flows for additional reserve information.)

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, 2009. 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.

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, 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.

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with SEC rules and regulations as well as with established industry practices. Management works closely with LaRoche to ensure accuracy of the data provided to LaRoche. On a semi-annual basis, management and staff meet with LaRoche to review properties and discuss assumptions to be used in the calculation of reserves.

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 interest or other parties’ working interest.

Kansas
Years Ended December 31,	Production		Cost of Production (per BOE)	Average Sales Price
	Oil (Bbl)	Gas (Mcf)		Oil (Bbl)	Gas (Per Mcf)
2009	217,000	-	$14.61	$54.48	-
2008	231,598	-	$17.21	$92.69	-
2007	178,311	-	$16.97	$66.42	-

Tennessee
Years Ended December 31,	Production		Cost of Production (per BOE)	Average Sales Price
	Oil (Bbl)	Gas (Mcf)		Oil (Bbl)	Gas (Per Mcf)
2009	5,750	78,000	$24.60	$54.87	$3.99
2008	6,396	104,043	$22.56	$88.20	$9.10
2007	6,877	117,129	$26.42	$64.81	$6.86

Average sales price for 2008 and 2007 noted in the two tables above have been changed from prior filings to reflect actual average sales prices.

Oil and Gas Drilling Activities

Kansas

In 2009, the Company drilled 1 SWD well in Kansas.

The results of the wells drilled in Kansas in 2009 are set out in the following table. The Company has a 100% working interest in the well.

Name of Well	Date Completed	Cumulative Production (Bbl)
Albers #2	11/2010	n/a- SWD

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 2009 the Company did not drill any new wells in the Swan Creek Field. The Company believes that drilling new gas wells in the Swan Creek Field itself 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 the fiscal years ending December 21, 2007, 2008 and 2009 the number of gross and net development wells drilled by the Company. 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 interest the Company owns in the gross wells.

	For Years Ending December 31,
	2009		2008		2007
Kansas	Gross	Net	Gross	Net	Gross	Net
Productive Wells	-	-	9	7.725	10	4.0
Dry Holes	-	-	3	2.625	6	5.25
Salt Water Disposal	1	1	-	-	-	-

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, 2009. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. One or more completions in the same bore hole are counted as one well.

	Gas		Oil
	Gross	Net	Gross	Net
Kansas	-	-	213	181
Tennessee	21	16	4	4
Total	21	16	217	185

Developed and Undeveloped Oil and Gas Acreage

As of December 31, 2009 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	14,921	12,130	7,450	6,333
Tennessee	3,120	2,370	5,192	4,543
Total	18,041	14,500	12,642	10,876

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. (REMOVED AND RESERVED)

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

The Company’s common stock is listed on the NYSE Amex exchange under the symbol TGC. The Company’s common stock was previously listed under the symbol TGC on the American Stock Exchange until its acquisition by NYSE in October 2008. The range of high and low closing prices for shares of common stock of the Company as reported on the NYSE Amex during the fiscal years ended December 31, 2009 and December 31, 2008 are set forth below.

	High	Low
For the Quarters Ending
March 31, 2009	$0.76	$0.40
June 30, 2009	0.75	0.45
September 30, 2009	0.61	0.46
December 31, 2009	0.65	0.43

March 31, 2008	$.0.68	$0.51
June 30, 2008	2.67	0.56
September 30, 2008	2.99	0.94
December 31, 2008	1.01	0.48

Holders

As of March 12, 2010 the number of shareholders of record of the Company’s common stock was 319 and management believes that there are approximately 8,790 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 2009 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 2009, the Company did not sell or issue any unregistered securities. Any unregistered equity securities that were sold or issued by the Company during the first three quarters of fiscal 2009 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 2009.

Equity Compensation Plan Information

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

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data have been derived from the Company’s financial statements, and should be read in conjunction with those financial statements, including the related footnotes. (In thousands, except per share data)

Year Ended December 31,

	2009	2008	2007	2006	2005
Income Statement Data:
Oil and Gas Revenues	$ 9,711	$ 15,570	$ 9,300	$ 8,896	$ 7,068
Production Cost and Taxes	5,315	5,888	4,323	3,287	3,046
General and Administrative	1,731	1,863	1,417	1,293	1,323
Interest Expense	634	608	333	169	473
Net Income (Loss)	(2,018)	170	3,510	2,141	1,088
Net Income (Loss) Attributable to Common Stockholders	(2,018)	170	3,510	2,141	1,088
Net Income (Loss) Attributable to Common Stockholders Per Share	$ (0.03)	$ 0.00	$ 0.06	$ 0.04	$ 0.02

As of December 31,

	2009	2008	2007	2006	2005
Balance Sheet Data:
Working Capital Surplus (Deficit)	$ 260	$ 646	$ 2,473	$ 873	$ (1,335)
Oil and Gas Properties, Net	12,360	14,142	16,940	12,704	9,676
Pipeline Facilities, Net	12,397	12,380	12,917	13,461	13,994
Total Assets	41,174	42,447	38,011	28,454	25,909
Long-Term Debt	10,062	10,052	4,316	2,731	118
Stockholders’ Equity	$ 26,843	$ 28,576	$ 28,103	$ 24,420	$ 21,961

No cash dividends had been declared or paid by the Company for the periods presented in the above tables.

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

Results of Operations

The Company reported a net loss to holders of common stock of $2.0 million or $0.03 per share in 2009 compared to a net income of $0.2 million or $0.00 per share in 2008 and compared to a net income of $3.5 million or $0.06 per share in 2007.

The Company realized revenues of $9.7 million in 2009 compared to $15.6 million in 2008 and $9.4 million in 2007. Revenues decreased $5.9 million from 2008 primarily due to a decrease in oil prices in Kansas as prices averaged $54.48 in 2009 compared to $92.69 in 2008. The average price received for Kansas oil sales in 2007 was $66.42.

Gas prices received for sales of gas from the Swan Creek Field averaged $3.99 per Mcf in 2009, $9.10 per Mcf in 2008 and $6.86 per Mcf in 2007. Oil prices received for sales of oil from the Swan Creek field averaged $54.87 per barrel in 2009, $80.20 per barrel in 2008 and $64.81 in 2007.

Production costs and taxes in 2009 decreased to $5.3 million from $5.9 million in 2008 and was $4.3 million in 2007.

Depletion, depreciation, and amortization for 2009 was $2.6 million, an increase from $2.2 million in 2008 and $1.6 million in 2007. The increase in 2009 over 2008 levels is primarily due to a $10.7 million increase in future development cost association with the proved reserves, partially offset by a 893 MBOE increase in reserves.

The Company’s general and administrative cost was $1.7 million in 2009, $1.9 million in 2008 and 1.4 million in 2007. The 2009, 2008 and 2007 cost included non-cash charges related to stock options of $ 0.2 million, $0.2 million, and $0.1 million respectively.

Professional fees were $0.3 million in 2009 and 2008 and $0.2 million in 2007. This increase in 2008 was due to the Company commencing its review of its internal controls over its financial reporting.

The Company’s public relation cost was $50,000 for 2009, compared to $41,000 for 2008 and $22,000 for 2007.

Interest expense was $0.6 million in 2009 and 2008 and $0.3 million in 2007. The increase in interest expense in 2009 and 2008 relates to increased borrowings from the Sovereign credit facility.

During 2009, the Company recorded a noncash unrealized loss on derivatives of $1.3 million or $0.02 per share. This loss was based on the fair value of the oil derivative agreement entered into in July 2009. (See Note 12 Derivatives and Note 13 Fair Value Measurement for additional information related to the derivative transaction and the valuation of this transaction.)

During 2008, the Company recorded an $11.6 million non-cash ceiling test writedown of its oil and gas properties. This writedown resulted from a significant reduction of the Company’s proved reserve value as of December 31, 2008 due to low year end oil prices.

The Company recorded a deferred tax asset of $0.2 million in 2009 relating to the Company’s net operating loss carry forwards and $5.2 million in 2008 with $1.6 million recognized as income tax expense.

Liquidity and Capital Resources

On June 29, 2006, the Company closed on a $50 million revolving senior credit facility between the Company and Citibank Texas, N.A. (“Citibank”). 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 million or the borrowing base in effect from time to time.

On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank as requested by the Company. Under the facility as assigned to Sovereign, loans and letters of credit are 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 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 assets. The Company’s initial borrowing base with Sovereign was set at $7.0 million.

On June 2, 2008, the Company entered into an amendment to its credit facility with Sovereign whereby the Company’s borrowing base was increased by the Bank as a result of its review of the Company’s currently owned producing properties. The borrowing base was raised to $11 million effective June 2, 2008. The amendment also set the interest rate to the greater of prime plus 0.25% or 6% per annum. The Company had previously utilized about $4.2 million of the facility, leaving approximately $6.8 million available for use by the Company upon this borrowing base increase.

The Company used $5.35 million of the then available $6.8 million for the purchase of the Riffe Field properties in Kansas.

Effective February 5, 2009, the Company amended its credit facility with Sovereign to provide for a monthly reduction of the Bank’s commitment by $0.15 million per month for the five month period of February through June 2009. This commitment reduction was not a cash payment obligation of the Company but had the effect of reducing the Company’s available borrowing base in monthly increments of $0.15 million under the Sovereign facility.

On July 9, 2009 the Company’s borrowing base was increased from $10.25 million to $11.0 million under the revolving senior credit facility between the Company and Sovereign on the completion of the regular semiannual borrowing base review. The $11.0 million borrowing base was again made subject to a monthly available credit reduction of $0.15 million per month beginning August 5, 2009.

On February 23, 2010, the Company entered into an amendment to its credit facility with Sovereign increasing the borrowing base from $10.25 million to $11.0 million on completion of the semiannual borrowing base review by Sovereign. The amendment also reduced the monthly commitment reduction from $0.15 million to $0.1 million and changed the maturity date to June 30, 2011. In addition, the amendment modified the covenant compliance calculations. This modification allowed the Company to exclude the first and second quarters of 2009. As of December 31, 2009, the Company was in compliance with all covenants. The next borrowing base review will take place in June 2010.

The total borrowing by the Company under the facility at December 31, 2008 and 2009 was $9.9 million.

Although the Company has not been required as of the date of this Report to make any payment of principal to Sovereign Bank under the borrowing base in effect at any time, the Company can make no assurance that in view of the conditions in the national and world economies, including the realistic possibility of low commodity prices being received for the Company’s oil and gas production for extended periods, that Sovereign may in the future make a redetermination of the Company’s borrowing

base to a point below the level of the installment or other payments to Sovereign in such amount and at such times in order to reduce the principal of the Company’s outstanding borrowing to a level not in excess of the borrowing base as it may be redetermined.

During 2009 and 2008, the Company remained focused on production and carefully used its cash flow and available credit to do so. However, the Company can make no assurance that it can continue normal operations indefinitely or for any specific period of time in the event of extended periods of low commodity prices, such as occurred in late 2008 and early 2009, or upon the occurrence of any significant downturn or losses in operations. In such event, the Company may be required to reduce costs of operations by various means, including not undertaking certain maintenance or reworking operations that may be necessary to keep some of the Company’s properties in production or to seek additional working capital by additional means such as issuance of equity including preferred stock or such other means as may be considered and authorized by the Company’s Board of Directors from time to time.

Net cash provided by operating activities was $1.7 million in 2009, $7.1 million in 2008 and $3.4 million in 2007. The reduction of cash provided by operating activities from 2008 to 2009 was primarily due to low product prices received during 2009 as compared to 2008. Cash flow used for working capital was $0.2 million in both 2009 and 2008. Cash provided by working capital was $0.2 million in 2007.

Net cash used in investing activities was $1.5 million in 2009, $14.9 million in 2008, and $3.1 million in 2007. The decrease in 2009 was primarily due to a reduction in investment of $11.0 million in oil and gas properties and $2.5 million in the Methane Project from 2008 levels.

In 2009 no cash was provided by or used in financing activities. Net cash provided by financing activities was $5.8 million in 2008 and $1.6 million in 2007. The decrease in 2009 was due to no new additional borrowings being made by the Company under the Sovereign credit facility.

Critical Accounting Policies

The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which require 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 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 customer’s location and usage is billed each month. Crude oil is stored and at the time of delivery to the purchasers, 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 costs of drilling, completing and equipping oil and gas wells.

Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write-downs were recorded in 2009 or 2007. However, in 2008 the Company incurred a ceiling limitation write-down in the amount of $11.6 million primarily due to the dramatically lower year-end oil prices in 2008 as compared to 2007 and the resulting significant downward adjustment of the Company’s estimated proved reserves. The effect of the ceiling write-down resulted in the Company recording a net income in 2008 of $0.2 million.

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 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, 2009 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’s asset retirement obligations relate to the plugging, dismantling and removal of wells drilled to date. The Company follows the requirements of FASB ASC 410, Asset Retirement Obligations and Environmental Obligations. Among other things, FASB ASC 410 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. 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%, when the original liability was recognized. In 2009, the retirement obligation for the Albers #2 SWD was recognized using the current credit adjusted risk free rate of 8%. The Company used an estimated useful life of wells ranging from 30-40 years and an estimated plugging and abandonment cost of $5,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.

Recent Accounting Pronouncements

On February 24, 2010, the FASB issued Accounting Standards Update (“ASU”) 2010-09, effective immediately, which amended ASC Topic 855, Subsequent Events. The amendment was made to address concerns about conflicts with SEC guidance and other practice issues. Among the provisions of the amendment, the FASB defined a new type of entity, termed an “SEC filer,” which is an entity required to file with or furnish its financial statements to the SEC. Entities other than registrants whose financial statements are included in SEC filings (e.g., businesses or real estate operations acquired or to be acquired, equity method investees, and entities whose securities collateralize registered securities) are not SEC filers. While an SEC filer is still required by U.S. GAAP to evaluate subsequent events through the date its financial statements are issued , it is no longer required to disclose in the financial statements that it has done so or the date through which subsequent events have been evaluated. The Company does not believe the changes have a material impact on our results of operations or financial position.

In January 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements. This update requires more robust disclosures about valuation techniques and inputs to fair value measurement. The update is effective for interim and annual reporting periods beginning after December 15, 2009. This update will have no material effect on the Company’s consolidated financial statements.

In July 2009, the FASB issued ASC 855-10-50, Subsequent Events which requires an entity to recognize in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed at the date of the balance sheet, including the estimates inherent in the process of the financial statements. The final rules were effective for interim and annual periods issued after June 15, 2009. The Company has adopted the policy effective September, 2009. There was no material effect on the Company’s consolidated financial statements as a result of the adoption.

In June 2009, the FASB issued ASC 105, Codification which establishes FASB Codification as the source of authoritative generally accepted accounting pronouncements (“U.S. GAAP”) recognized by the FASB to be applied by nongovernmental entities. The final rule was effective for interim and annual periods issued after September 15, 2009. The Company has adopted the policy effective September 30, 2009. There was no material effect on the presentation of the Company’s consolidated financial statements as a result of the adoption of ASC 105.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements (modernization of Oil and Gas Reporting). In January 2010, the FASB released ASU 2010-03, Extractive Activities- Oil and Gas (“Topic 932); Oil and Gas Reserve Estimation and Disclosures aligning U.S. GAAP standards with the SEC’s new rules. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations.

Key revisions include: (a) changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period when the full cost ceiling was exceeded and subsequent pricing exceeds pricing at the end of a reporting period, (b) the ability to include nontraditional resources in reserves, (c) the use of new technology for determining reserves, and (d) permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. ASU 2010-03 is effective for annual periods ending on or after December 31, 2009. Adoption of Topic 932 did not have a material impact on the Company’s results of operations or financial position.

In September 2006, the FASB issued ASC 820, “Fair Value Measurements”, which applies under most other accounting pronouncements that require or permit fair value measurements. FASB ASC 820 provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements. FASB ASC 820 had originally been effective for financial statements issued for fiscal years beginning after November 15, 2007, however the FASB has agreed on a one year deferral for all non-financial assets and liabilities. The Company adopted FASB ASC 820 effective January 1, 2008. Adoption of this statement did not have a material impact on the Company’s financial condition, results of operations, and cash flows.

Contractual Obligations

The following table summarizes the Company’s contractual obligations due by period as of December 31, 2009: (in thousands)

Contractual Obligations	Total	Less than 1 year	1-3 years
Long-Term Debt Obligations (See Note 9 Long Term Debt)	$ 10,181	$ 119	$ 10,062
Operating Lease Obligations (See Note 10 Commitments and Contingencies)	262	58	204
Total	$ 10,443	$ 177	$ 10,266

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 range from a low of $29.87 per barrel to a high of $70.40 per barrel during 2009. Gas prices realizations ranged from monthly low of $2.84 per Mcf to a monthly high of $6.16 per Mcf during the same period.

In order to help mitigate commodity price risk, the Company has entered into a long term fixed price contract for MMC gas sales. In addition the Company has entered into derivative agreement on a specified number of barrels of oil that currently constitutes about two-thirds of the Company’s daily production.

On July 28, 2009 the Company entered into a two-year agreement on crude oil pricing applicable to a specified number of barrels of oil that currently constitutes about two-thirds of the Company’s daily production. The agreement was effective beginning August 1, 2009. The “costless collar” agreement has a $60.00 per barrel floor and $81.50 per barrel cap on a volume of 9,500 barrels per month during the period from August 1, 2009 through December 31, 2010, and 7,375 barrels per month from January 1

through July 31, 2011. The prices referenced in this agreement are WTI NYMEX. While the agreement is based on WTI NYMEX prices, the Company receives a price based on Kansas Common plus bonus, which results in approximately $7 per barrel less than current WTI NYMEX prices.

Under a “costless collar” agreement, no payment would be made or received by the Company, as long as the settlement price is between the floor price and cap price (“within the collar”). However, if the settlement price is above the cap, the Company would be required to pay the counterparty an amount equal to the excess of the settlement price over the cap times the monthly volumes hedged. Also, if the settlement price is below the floor, the counterparty would be required to pay the Company the deficit of the settlement price below the floor times the monthly volumes hedged.

This agreement is primarily intended to help maintain and stabilize cash flow from operations if lower oil prices return, while providing some upside if prices increase above the cap. If lower oil prices return, this agreement may help to maintain the Company’s production levels of crude oil by enabling the company to perform some ongoing polymer or other workover treatments on then-existing producing wells in Kansas.

Interest Rate Risk

At December 31, 2009, the Company had debt outstanding of approximately $10.2 million including, as of that date, $9.9 million owed on its credit facility with Sovereign Bank. The interest rate on the credit facility is variable at a rate equal to the prime rate plus 0.25% with a floor of 6%. The Company’s remaining debt of $0.3 million has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company annual interest cost in 2009 fluctuated based on short-term interest rates on approximately 97% of its total debt outstanding at December 31, 2009. During 2009, the Company paid $0.6 million of interest on the Sovereign line of credit. 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 $0.1 million assuming borrowed amounts under the credit facility remained at the same amount owed as of December 31, 2009. The Company did not have any open derivative contracts relating to interest rates at December 31, 2009.

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 would 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 financial position, results of operations and cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None

ITEM 9A(T). CONTROLS AND PROCEDURES

The Company’s Chief Executive Officer and Chief 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 Chief 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 is 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.

Managements 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 Rules 13a-15(f) and 15d-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

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.

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.

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 internal control over financial reporting as of December 31, 2009. 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, 2009.

This annual 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.

Changes in Internal Controls

During 2009, the Company engaged Risked Revenue Energy Associates to assist Management in valuing the derivative transaction. This valuation is then compared to counterparty’s market value for validation purposes.

There have been no other changes to the Company’s system of internal control over financial reporting during the year ended December 31, 2009 that have materially affected, or are 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 2010 Annual Meeting of Stockholders will be held on June 21, 2010 at 9:00 am at the Homewood Suites by Hilton, 10935 Turkey Drive, Knoxville, Tennessee 37922.

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 2010 Annual Meeting of Stockholders (the “Proxy Statement”).

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE

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 STOCKHOLDERS 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 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, 2009.

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	3,021,000	$0.42	2,539,368
Equity compensation plans not approved by security holders3	-	n/a	-
Total	3,021,000	$0.42	2.539,368

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item as to transaction 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 ACCOUNTING FEES AND SERVICES

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

3 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 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 amendments to the Plan to increase the aggregate number of shares that may be issued under the Plan to 7,000,000 shares. The most recent amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another 10 years was approved by the Company Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held June 2, 2008.

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES

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

Financial Statements:

Consolidated Balance Sheets

Consolidated Income Statements

Consolidated Statements of Stockholders Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

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.

Exhibits.

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

Exhibit Index

Exhibit Number	Description
3.1	Charter (Incorporated by reference to Exhibit 3.7 to the registrant’s registration statement on Form 10-SB filed August 7, 1997 (the “Form 10-SB”))
3.2	Articles of Merger and Plan of Merger (taking into account the formation of the Tennessee wholly-owned subsidiary for the purpose of changing the Company’s domicile and effecting reverse split) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
3.3	Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to Exhibit 3.9 to the registrant’s annual report on Form 10-KSB filed April 15, 1999 (the “1998 Form 10-KSB”))
3.4	Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form 10-KSB)
3.5	Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to Exhibit 3.11 to the registrant’s annual report on Form 10-KSB filed April 14, 2000 (the “1999 Form 10-KSB”))

3.6	By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
3.7	Amendment and Restated By-laws dated May 19, 2005 (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	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)
10.4	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)
10.5	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)
10.6	Subscription Agreement of Hoactzin Partners, L.P. for the Company’s ten well drilling program on its Kansas Properties dated August 3, 2007 (Incorporated by reference to Exhibit 10.15 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 filed March 31, 2008 [the “2007 Form 10-K”])..
10.7	Agreement and Conveyance of Net Profits Interest dated September 17, 2007 between Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as Grantee (Incorporated by reference to Exhibit 10.16 to the 2007 Form 10-K).
10.8	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 (Incorporated by reference to Exhibit 10.17 to the 2007 Form 10-K).
10.9	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 (Incorporated by reference to Exhibit 10.18 to the 2007 Form 10-K).

10.10	Management Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin Partners, L.P. (Incorporated by reference to Exhibit 10.20 to the 2007 Form 10-K).
10.11	Amendment to the Tengasco, Inc. Stock Incentive Plan dated February 1, 2008, 2008 (Incorporated by reference to Exhibit 4.1 to the registrant’s registration statement on Form S-8 filed June 3, 2008)
10.12	Assignment of Leases from Black Diamond Oil, Inc. to Tengasco, Inc. (Incorporated by reference to Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008 filed on August 11, 2008).
10.13*	Energy Option Transaction Confirmation Agreement (Put) between Tengasco, Inc. and Macquarie Bank Limited dated September 17, 2009.
10.14*	Energy Option Transaction Confirmation Agreement (Call) Amendment between Tengasco, Inc. and Macquarie Bank Limited dated September 17, 2009.
14	Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s annual report on Form 10-K filed March 30, 2004)
21	List of subsidiaries (Incorporated by reference to Exhibit 21 to the 2007 Form 10-K).
23.1*	Consent of LaRoche Petroleum Consultants, Ltd.
23.2*	Consent of Risked Revenue Energy Associates
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Exhibit filed with this Report

Signatures

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

Dated: March 31, 2010

Tengasco, Inc.

(Registrant)

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey,

Chief Executive Officer

By: s/ Michael J. Rugen

Michael J. Rugen,

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 31,2010
s/ Matthew K. Behrent Matthew K. Behrent	Director	March 31, 2010
s/ John A. Clendening John A. Clendening	Director	March 31, 2010
s/Carlos P. Salas Carlos P. Salas	Director	March 31, 2010
s/ Peter E. Salas Peter E. Salas	Director	March 31, 2010
s/ Michael J. Rugen Michael J. Rugen	Principal and Financial Accounting Officer	March 31, 2010

Tengasco, Inc.

and Subsidiaries

Consolidated Financial Statements

Years Ended December 31, 2009, 2008, and 2007

Report of Independent Registered Public Accounting Firm	F-4
Consolidated Financial Statements Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-7
Consolidated Statements of Stockholders’ Equity	F-8
Consolidated Statements of Cash Flows	F-9
Notes to Consolidated Financial Statements	F-10

Report of Independent Registered Public Accounting Firm

To the Board of Directors and

Stockholders of Tengasco, Inc.

We have audited the accompanying consolidated balance sheets of Tengasco, Inc. (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2009. The Company’s management is responsible for these consolidated financial statements. 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 was not required for 2009 to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Tengasco, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ Rodefer Moss & Co, PLLC

Certified Public Accountants

Knoxville, Tennessee

March 26, 2010

F-4

Tengasco, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except per share and share data)

	December 31,
	2009	2008

Assets

Current
Cash and cash equivalents	$ 422	$ 245
Accounts receivable	1,130	1,104
Participant receivables	18	24
Inventory	581	476
Other current assets	20	10
Total current assets	2,171	1,859

Restricted cash	121	121
Loan fees	146	202
Oil and gas properties, net (full cost accounting method)	12,360	14,142
Pipeline facilities, net	12,397	12,380
Methane project, net	4,403	4,357
Other property and equipment, net	306	285
Deferred tax asset	9,270	9,101

Total assets	$ 41,174	$ 42,447

See accompanying Notes to Consolidated Financial Statements

F-5

Tengasco, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except per share and share data)

	December 31,
	2009	2008

Liabilities and Stockholders’ Equity

Current liabilities
Current maturities of long-term debt	$ 119	$ 75
Accounts payable	742	701
Accrued liabilities	302	437
Unrealized derivative liability	748	-
Total current liabilities	1,911	1,213

Asset retirement obligation	450	656
Deferred conveyance oil and gas properties	490	1,097
Prepaid revenues	853	853
Long term debt, less current maturities	10,062	10,052
Unrealized derivative liability	565	-
Total liabilities	14,331	13,871

Stockholders’ equity
Common stock, $.001 par value: authorized 100,000,000
Shares; 59,760,661 and 59,350,661 shares issued and outstanding	60	59
Additional paid in capital	55,277	54,993
Accumulated deficit	(28,494)	(26,476)
Total stockholders’ equity	26,843	28,576

Total liabilities and stockholders’ equity	$41,174	$ 42,447

See accompanying Notes to Consolidated Financial Statements

F-6

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per share and share data)

	Years ended December 31,
	2009	2008	2007
Revenues and other income
Oil and gas revenues	$ 9,711	$ 15,570	$ 9,300
Pipeline transportation revenues	19	12	51
Interest income	1	19	17
Total revenues and other income	9,731	15,601	9,368

Cost and expenses
Production costs and taxes	5,315	5,888	4,323
Depreciation, depletion, and amortization	2,571	2,160	1,631
Ceiling test impairment	-	11,608	-
General and administrative	1,731	1,863	1,417
Professional fees	304	264	232
Public relations	50	41	22
Total cost and expenses	9,971	21,824	7,625

Net income (loss) from operations	(240)	(6,223)	1,743

Other expense
Interest expense	634	608	333
Unrealized loss on derivatives	1,313	-	-
Total other expense	1,947	608	333

Deferred tax benefit	169	8,625	2,100
Income tax expense	-	(1,624)	-

Net income (loss)	$ (2,018)	$ 170	$ 3,510

Net income (loss) per share
Basic	$ (0.03)	$ 0.00	$ 0.06
Fully diluted	$ (0.03)	$ 0.00	$ 0.06

Shares used in computing earnings per share
Basic	59,408,990	59,248,446	59,117,176
Diluted	59,408,990	61,492,446	60,827,224

See accompanying Notes to Consolidated Financial Statements

F-7

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

(In thousands, except per share and share data)

	Common Stock		Paid-in Capital	Accumulated Deficit	Total
	Shares	Amount
Balance, December 31, 2006	59,003,284	$59	$54,517	$(30,156)	$24,420

Net income	-	-	-	3,510	3,510
Options and compensation expense	145,250	-	169	-	169
Commons stock issued for exercise of warrants	7,216	-	3	-	3
Balance, December 31, 2007	59,155,750	$59	$54,690	$(26,646)	$28,103

Net income	-	-	-	170	170
Options and compensation expense	-	-	213	-	213
Shares issued for compensation	30,000	-	18	-	18
Commons stock issued for exercise of warrants	164,911	-	72	-	72
Balance, December 31, 2008	59,350,661	$59	$54,993	$(26,476)	$28,576

Net income/loss	-	-	-	(2,018)	(2,018)
Options and compensation expense	-	-	174	-	174
Commons stock issued for exercise of options	410,000	1	110	-	111
Balance, December 31, 2009	59,760,661	$60	$55,277	$(28,494)	$26,843

See accompanying Notes to Consolidated Financial Statements

F-8

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

	Years Ended December 31,
	2009	2008	2007
Operating activities
Net income (loss)	$ (2,018)	$ 170	$ 3,510
Adjustments to reconcile net income to net cash
Provided by operating activities
Depletion, depreciation, and amortization	2,571	2,160	1,631
Accretion on asset retirement obligation	48	155	71
Ceiling test impairment	-	11,608	-
Loss on sale of vehicles/equipment	-	10	5
Compensation and services paid in stock options	174	231	116
Deferred tax benefit	(169)	(7,001)	(2,100)
Unrealized loss on derivatives	1,313	-	-
Changes in assets and liabilities
Accounts receivable	(26)	(47)	(337)
Participant receivables	6	25	(37)
Other current assets	(10)	-	-
Inventory	(105)	(15)	90
Accounts payable	41	(203)	218
Accrued liabilities	(137)	67	332
Settlement on asset retirement obligations	-	(30)	(52)
Net cash provided by operating activities	1,688	7,130	3,447
Investing activities
Additions to oil and gas properties	(1,020)	(11,965)	(5,191)
Drilling program portion of additional drilling	-	-	3,850
Proceeds from sale of oil and gas properties	142	-	-
Net additions to Methane Project	(184)	(2,707)	(1,650)
Net additions to pipeline facilities	(418)	(7)	-
Net additions to other property & equipment	-	(189)	(155)
Net cash (used in) investing activities	(1,480)	(14,868)	(3,146)
Financing activities
Proceeds from exercise of options/warrants	111	72	56
Proceeds from borrowings	-	5,889	1,696
Loan fees	-	(69)	(77)
Repayment of borrowings	(142)	(136)	(119)
Net cash provided by (used in) financing activities	(31)	5,756	1,556

Net change in cash and change equivalents	177	(1,982)	1,857
Cash and cash equivalents, beginning of period	245	2,227	370
Cash and cash equivalents, end of period	$ 422	$ 245	$ 2,227
Supplemental cash flow information:
Interest paid	$ 634	$ 447	$ 262
Supplemental non-cash investing and financing activities:
Financed Company vehicles	$ 196	-	-

See accompanying Notes to Consolidated Financial Statements

F-9

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Description of Business and Significant Accounting Policies

Tengasco, Inc. is a Tennessee corporation (“Tengasco” or the “Company”).

The Company is in the business of exploration and production of oil and natural gas. The Company’s primary area of oil exploration and production is in Kansas. The Company’s primary area of gas exploration and production is the Swan Creek Field in Tennessee.

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’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) owns and operates 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 nations existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.

Principles of Consolidation

The accompanying consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company, and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances.

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. generally accepted accounting principles 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 oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.

Cash and Cash Equivalents

Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.

F-10

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Inventory

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

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic surveys, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs, which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. in 2009, 2008, and 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 currently has $0.1 million in unevaluated properties as of December 31, 2009. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) discounted at 10% (ceiling). Prior to the year ending December 31, 2009, the ceiling was calculated using the year end price. If the net capitalized costs exceed this limit, the excess is charged to earnings and may not be reversed in subsequent periods. During 2008, the Company recorded an impairment of $11.6 million as a result of the year end December 31, 2008 ceiling test analysis. No impairment was required for the years ended December 31, 2009 and 2007.

Asset Retirement Obligation

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to oil and gas properties. For oil and gas properties, this is the period in which the well is drilled or acquired. A legal obligation is a liability that a party is required to settle as a result of an existing law, statute, ordinance or contract. Each period, we accrete the liability to its then present value and depreciate the capitalized cost over the useful life of the related asset.

F-11

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Pipeline Facilities

The pipeline was placed into service upon its completion on March 8, 2001. The pipeline is being depreciated over its estimated useful life of 30 years beginning at the time it was placed in service.

Manufactured Methane Facilities

The methane facilities were placed into service on April 1, 2009. The methane facilities are being depreciated over an estimated useful life of 13 years and 9 months beginning at the time it was placed in service.

Other Property and Equipment

Other property and equipment is 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 two to seven years.

Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Stock-Based Compensation

The Company accounts for stock-based compensation in accordance with FASB ASC 718 Compensation-Stock Compensation. ASC 718 requires all share-based payments to employees to be recognized in our consolidated statements of operations based on their estimated fair values. We recognize expense on a straight line basis over the vesting period of the options. The Company recorded compensation expense of $0.2 million in 2009 and 2008 and $0.1 million in 2007.

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, the Company believes no allowance for doubtful accounts as of December 31, 2009 and 2008 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

F-12

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

currently has a net operating loss carry forward of $15.5 million.

As of December 31, 2008, the Company also had a deferred tax asset totaling $3.9 million related to a ceiling test write-down of $11.6 million. This deferred tax asset arose from differences between the financial statement carrying value of the Company’s oil and gas properties and their respective income tax bases (temporary differences) after taking into consideration the reduced depletion expense from the ceiling test write down. To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of this deferred tax asset will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Management has determined that it is more likely than not that all of this deferred tax asset will be realized. The $3.9 million deferred tax asset related to the ceiling test write-down is in addition to the deferred tax assets resulting from the Company’s net operating loss carry-forwards. The total deferred tax asset at December 31, 2009 is $9.3 million.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At December 31, 2009, such cash in banks is in excess of the FDIC insurance limit. The Company’s primary business activities include oil and gas sales to a limited number of customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk.

The Company sells a majority of its crude oil primarily to one customer in Tennessee and two customers in Kansas. Additionally, the Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field. 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 may have a significant adverse effect on the Company’s projected results of operations.

Revenue from the top three purchasers accounted for 85.1%, 10.5% and 3.1% of total oil and gas revenues for year ended December 31, 2009. Revenue from the top three purchasers accounted for 93.6%, 3.5% and 2.5% of total oil and gas revenues for the year ended December 31, 2008. Revenue from the top three purchasers accounted for 91.4%, 4.9% and 3.7% of total oil and gas revenues for the year ended December 31, 2007.

F-13

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Income per Common Share

In accordance with FASB ASC 260, Earnings Per Share, basic income per share is based on 59,408,990, 59,248,446 and 59,117,176 weighted average shares outstanding for the years ended December 31, 2009, 2008 and 2007, 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. The numbers of dilutive shares outstanding were 2,244,000 and 1,710,048 for the years ended December 31, 2008 and 2007, respectively. Because the Company had a net loss for the year ended December 31, 2009, dilutive potential shares of common stock are excluded as they are anti-dilutive.

Fair Value of Financial Instruments

Fair value of cash and cash equivalents, investments and short term debt approximate their carrying value due to the short period of time to maturity. Fair value of long term debt is based on quoted market prices or pricing models using current market rates, which approximate carrying value. (See Note 12 Fair Value Measurement)

Derivative Financial Instruments

The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. We do not enter into the derivative instruments for speculative trading purposes. We present the fair value of our derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. (See Note 13 Derivatives)

Reclassifications

Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income.

2. Recent Accounting Pronouncements

F-14

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

In January 2010, the FASB issued ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”. This update requires more robust disclosures about valuation techniques and inputs to fair value measurements. The update is effective for interim and annual reporting periods beginning after December 15, 2009. This update will have no material effect on the Company’s consolidated financial statements.

In July 2009, the FASB issued ASC 855-10-50, “Subsequent Events”, which requires an entity to recognize in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed at the date of the balance sheet, including the estimates inherent in the preparation of the financial statements. The final rules were effective for interim and annual periods issued after June 15, 2009. The Company has adopted the policy effective September, 2009. There was no material effect on the Company’s consolidated financial statements as a result of the adoption.

On December 31, 2008, the SEC published the final rules and interpretations updating its oil and gas reporting requirements (“Modernization of Oil and Gas Reporting”). In January 2010, the FASB released ASU 2010-03, Extractive Activities- Oil and Gas (“Topic 932); Oil and Gas Reserve Estimation and Disclosures aligning U.S. GAAP standards with the SEC’s new rules. Many of the revisions are updates to definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions include: (a) changes to the pricing used to estimate reserves utilizing a 12-month average price rather than a single day spot price which eliminates the ability to utilize subsequent prices to the end of a reporting period when the full cost ceiling was exceeded and subsequent pricing exceeds pricing at the end of a reporting period, (b) the ability to include nontraditional resources in reserves, (c) the use of new technology for determining reserves, and (d) permitting disclosure of probable and possible reserves. The SEC will require companies to comply with the amended disclosure requirements for registration statements filed after January 1, 2010, and for annual reports on Form 10-K for fiscal years ending on or after December 15, 2009. ASU 2010-03 is effective for annual periods ending on or after December 31, 2009. Adoption of Topic 932 did not have a material impact on the Company’s results of operations or financial position.

F-15

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

3. Related Party Transactions

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Ten 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. and the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. Carlos P. Salas, a director of the Company, has an interest in Hoactzin but is not a controlling person of Hoactzin. Under the terms of the Ten Well Program, Hoactzin was to pay the Company $0.4 million for each well in the Ten Well Program completed as a producing well and $0.25 million for each well drilled that was non-productive. The terms of the Ten Well 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 and if net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Ten Well Program.

In March 2008, the Company drilled and completed the tenth and final well in the Ten Well Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 61 barrels per day in total. Hoactzin paid a total of $3.85 million (the “Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being determined as $5.2 million. 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.

F-16

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Although production level of the Program wells will decline with time in accordance with expected decline curves for these types of wells, based on the drilling results of the wells in the Ten Well Program and the current price of oil, the Program wells would be expected to reach the Payout Point in approximately four years solely from the oil revenues from the wells. However, under the terms of the Company’s agreement with Hoactzin, reaching the Payout Point may be accelerated by operation of a second agreement by which Hoactzin will apply 75% of the net proceeds it receives from a methane extraction project discussed below developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”), to the Payout Point. Those methane project proceeds when applied may result in the Payout Point being achieved sooner than the estimated four year period based solely upon revenues from the Program wells.

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, pursuant to an additional agreement with the Company was conveyed a 75% net profits interest in the methane extraction project developed by MMC at the Carter Valley landfill owned and operated by Republic Services in Church Hill, Tennessee (the "Methane Project"). 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 Ten Well 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.

On September 17, 2007, the Company also entered into an additional agreement with Hoactzin providing that if the Program and the Methane Project interest in combination failed to return net revenues to Hoactzin equal to 25% of the Purchase Price it paid for its interest in the Ten Well Program by December 31, 2009, then Hoactzin would have an option to exchange up to 20% of its net profits interest in the Methane Project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the Purchase Price less the net proceeds received at the time of any exchange. At the time the agreement was negotiated, the Company's forecast of the probable results of the projects indicated that there was little risk that the option to acquire preferred stock would ever arise, so the Company placed no significant value to the preferred stock option. By December 31, 2009 the amount of net revenues received by Hoactzin from the Ten Well Program has reduced the Company’s obligation to Hoactzin for the amount of the funds it had advanced for the Purchase Price from $3.85 million to $1.3 million. The conversion option would be set at issuance of the preferred stock at the then twenty business day trailing average closing price of Company stock on the NYSE Amex. Hoactzin has a similar option each year after 2009 in which Hoactzin’s then-unrecovered Purchase Price at the beginning of the year is not reduced 20% further by the end of that year, using the same conversion option calculation at date of the subsequent year’s issuance if any. The Company, however, may in any year make a cash payment from any source in the amount required to prevent such an exchange option for preferred stock from arising. In addition, the conversion right is limited to no more than 19% of the outstanding common shares of the Company.

F-17

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

In the event Hoactzin’s 75% net profits interest in the Methane Project were fully exchanged for preferred stock, by definition the reduction of that 75% interest to a 7.5% net profits interest that was agreed to occur upon the receipt of 1.3547 of the Purchase Price by Hoactzin could not happen because the larger percentage interest then exchanged, no longer exists to be reduced. Accordingly, Hoactzin would retain no net profits interest in the Methane Project after a full exchange of Hoactzin’s 75% net profits interest for preferred stock.

Under this exchange agreement, if no proceeds at all were received by Hoactzin through 2009 or in any year thereafter (i.e. a worst-case scenario already highly unlikely in view of the success of the Program), then Hoactzin would have an option to exchange 20% of its interest in the Methane Project in 2010 and each year thereafter for preferred stock with liquidation value of 100% of the Purchase Price (not 135%) convertible at the trailing average price before each year’s issuance of the preferred stock. The maximum number of common shares into which all such preferred stock could be converted cannot be calculated given the formulaic determination of conversion price based on future stock price.

However, revenues from the Ten Well Program have resulted in 61% of the Purchase Price having already been reached. Accordingly, it is highly unlikely that any requirement to issue preferred stock will arise in 2010 or any succeeding years.

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 interest 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 interest in its managed properties or five years.

4. Deferred Conveyance/Prepaid Revenues

The Company has adopted a deferred conveyance/prepaid revenues presentation of the transactions between the Company and Hoactzin Partners, L.P. on September 17, 2007 to more clearly present the effects of the three-part transaction consisting of the Ten Well Program, the Methane Project and a contingent exchange option agreement.

F-18

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

To reflect the deferred conveyance, the Company has allocated $0.9 million of the $3.85 million Purchase Price paid by Hoactzin for its interest in the Ten Well Program to the Methane Project, based on a relative fair value calculation of the Methane Project’s portion of the projected payout stream of the combined two projects as seen at the inception of the agreement, utilizing then current prices and anticipated time periods when the Methane Project would come on stream. The Ten Well Program at inception was $2.95 million and the prepaid revenues were $0.9 million.

The Company has established separate deferred conveyance and prepaid revenue accounts for the Ten Well Program and the Methane Project. Release of the deferred amounts to the Ten Well Program will be made as proceeds are actually distributed to Hoactzin. Release will be made on the respective proceeds only as to each project until either one or both satisfy the threshold amount that removes the contingent equity exchange option. The prepaid revenues will be released using the units of production method.

The reserve information for the parties’ respective Ten Well Program interests as of December 31, 2009 is indicated in the table below. Reserve reports are obtained annually and estimates related to those reports are updated upon receipt of the report. These calculations were made using commodity prices based on the twelve month arithmetic average of the first day of the month price for the period January through December 2009 as required by SEC regulations. The table below reflects eventual pay as occurring through the realization of proceeds at prices used in the reserve report dated December 31, 2009 of approximately $53.81 per barrel.

F-19

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Reserve Information for Ten Well Program Interest for the Year Ended December 31, 2009

	Barrels Attributable to Party’s Interest MBbl	Future Cash Flows Attributable to Party’s Interest (in thousands)	Present Value of Future Cash Flows Attributable to Party’s Interest (in thousands)
Tengasco	29.5	$706.1	$431.6
Hoactzin Partners, L.P.	88.5	$2,118.3	$1,294.8

As of year-end 2009, the original invested amount of $3.85 million has been reduced to $1.3 million. This amount is the total of the deferred conveyance of $0.5 million and the prepaid revenue account of $0.85 million. Hoactzin’s first right to convert its invested amount of $3.85 million into preferred stock is only exercisable to the extent Hoactzin’s investment has not been reduced by 25% by the end of 2009. For each year after 2010 in which Hoactzin’s then-unrecovered invested amount at the beginning of the year is not reduced 20% further by the end of that year, Hoactzin has a similar option. Consequently, Hoactzin is already precluded by these results from any possibility of exercising its contingent option under the exchange agreement to convert into preferred stock until the year ending December 31, 2011 at the earliest. All of the $2.5 million paid from the program has been from the Ten Well Program and the deferred conveyance account has been reduced from $3 million to $0.5 million.

As noted, in future periods, the Company anticipates that this Hoactzin investment will continue to be further reduced by sales of oil produced from the Ten Well Program, or methane produced from the Methane Project, or both. From inception of the project through December 31, 2010, the Company projects that the original $3.85 million Purchase Price will be reduced by 81% to $0.7 million. For the year ending December 31, 2011, the amount is projected to be reduced to zero. As a result, Hoactzin’s contingent option to exchange for preferred stock would fully terminate without any further annual reduction tests. These projections are based upon expected production levels from the oil wells in the Ten Well Program and an estimated 400 Mcf/day production from the Methane Project using $40 oil prices and a $5 per Mcf gas sales price net of operating expenses. The projection will vary with the actual oil and gas prices, production volumes, and expenses experienced in 2010 and 2011. Based on these projections the Company considers that it is a remote contingency that any right of Hoactzin to elect to exchange its Methane Project interest for Company preferred stock will ever arise. However, in the event of a conversion of Hoactzin’s Methane Project interest for Company preferred stock as set out in limited circumstances in the applicable agreement, and which the Company anticipates is highly unlikely, there would be a debit to the deferred conveyance liability and the prepaid revenue account for both the Ten Well Program and Methane Project because no contingent option would remain on such a conversion and the Company would simultaneously credit preferred stock in the converted amount.

F-20

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

In the event of the termination of the option to convert into preferred stock because the $3.85 million has been repaid from the Ten Well Program or Methane Project or both, the applicable oil and gas properties will be deemed to have been fully conveyed to Hoactzin and the Ten Well Program account, will be credited and the liability will be removed, as at this time the price received for the program will be fixed and determinable.

5. Oil and Gas Properties

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

	December 31,
	2009	2008
Oil and gas properties, at cost	$ 24,182	$ 23,031
Unevaluated properties	109	1,243
Accumulated depreciation, depletion and amortization	(11,931)	(10,132)
Oil and gas properties, net	$ 12,360	$ 14,142

During the years ended December 31, 2009, 2008, and 2007, the Company recorded depletion expense of $1.8 million, $1.4 million and $0.8 million, respectively.

During 2009, the Company received $142,000 in proceeds for the disposal of the Deutsch, Howlier, Landers, and Pfeiffer properties. (See Note 23, Supplemental Oil and Gas Information, Standardized Measure of Discounted Net Cash Flows for information regarding the reserve value impact of these sales.)

6. Pipeline Facilities

In 1996, the Company began construction of a 65-mile pipeline connecting the Swan Creek development project to a gas purchaser and 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 depreciation expense of $0.4 million, for the year ended December 31, 2009, and $0.5 million for the years ended December 31, 2008, and 2007. Gross costs were $16.8 million and $16.3 million and accumulated depreciation was $4.4 million and $4.0 million at December 31, 2009 and 2008, respectively.

F-21

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

7. Manufactured Methane Facility

The methane facility was placed in service on April 1, 2009, and is being depreciated over an estimated useful life of 13 years and 9 months. At December 31, 2009 gross costs were $4.5 million. Depreciation expense during 2009 was $0.1 million.

8. Other Property and Equipment

Other property and equipment consisted of the following: (in thousands)

December 31,	Depreciable Life	2009	2008
Machinery and equipment	5-7 yrs	$ 831	$ 831
Vehicles	2-5 yrs	561	556
Other	5 yrs	64	64
Total		1,456	1,451
Less accumulated depreciation		(1,150)	(1,166)
Other property and equipment-net		$ 306	$ 285

The Company uses the straight-line method of depreciation for other property and equipment

9. Long-Term Debt

Long-term debt to unrelated entities consisted of the following: (in thousands)

December 31,	2009	2008
Note payable to a financial institution, with interest only payment until maturity. (See Note 19 Bank Debt)	$ 9,900	$ 9,900
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $20,000	281	227
Total long-term debt	10,181	10,127
Current maturities	119	75
Long-term debt, less current maturities	$10,062	$10,052

10. 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.

F-22

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

On March 1, 2010, the Company entered into a lease for office space in Knoxville, Tennessee. The term of the lease is 41 months (five of which are free) and expires on July 31, 2013. The payment on this lease is $7,284 per month.

Future non-cancellable commitments related to this lease are as follows (in thousands):

Year
2010	$ 58
2011	73
2012	80
2013	51
	$262

Office rent expense for each of the three years ended December 31, 2009, 2008 and 2007 was $0.1 million.

11. Black Diamond Purchase

Effective as of July 1, 2008, the Company purchased from Black Diamond Oil, Inc. 80 barrels per day of oil producing properties and related leases in Rooks County, Kansas for $5.35 million. The Company also acquired producing oil wells and salt water disposal wells, equipment, and the underlying working interests in leases comprising what is known as the Riffe field that had been owned by Black Diamond for many years. The purchase price was paid primarily from borrowings under its credit facility with Sovereign Bank and from company cash on hand. Following the purchase, the Company has borrowed a total of $9.9 million under its credit facility.

12. Fair Value Measurements

FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markers for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:

Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 Inputs to the valuation methodology include:

F-23

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Quoted prices for similar assets or liabilities in active markets; Quoted prices for identical or similar assets or liabilities in inactive markets;

Inputs other than quoted prices that are observable for the asset or liability;

Inputs that are derived principally from or corroborated by observable market data by correlation or other means.

If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability

Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs. Following is a description of the valuation methodologies used for assets measured at fair value.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

The following table sets forth by level, within the fair value hierarchy, the Company’s liabilities at fair value as of December 31, 2009. (in thousands)

	Level 1	Level 2	Level 3

Derivative liabilities	-	$1,313	-

Total liabilities at fair value	$ -	$1,313	$-

13. Derivatives

F-24

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The agreement was effective beginning August 1, 2009. The “costless collar” agreement has a $60.00 per barrel floor an $81.50 per barrel cap on a volume of 9,500 barrels per month during the period from August 1, 2009 through December 31, 2010, and 7,375 barrels per month from January 1 through July 31, 2011. The prices referenced in this agreement are WTI NYMEX. While the agreement is based on WTI NYMEX prices, the Company receives a price based on Kansas Common plus bonus, which results in approximately $7 per barrel less than current WTI NYMEX prices. The average price per barrel received by the Company in the first quarter 2009 was $35.74, $52.52 for the second quarter 2009, $60.96 for the third quarter 2009 and $68.69 for the fourth quarter 2009.

This agreement is primarily intended to help maintain and stabilize cash flow from operations if lower oil prices return, while providing at least some upside if prices increase above the cap. If lower oil prices return, this agreement may help to maintain the Company’s production levels of crude oil by enabling the company to perform some ongoing polymer or other workover treatments on then existing producing wells in Kansas.

As of December 31, 2009, our open forward positions on our outstanding “costless collar” agreements, all of which are with Macquarie Bank Limited (“Macquarie”), were as follows:

Period	Monthly Volume	Total Volume	Floor/Cap NYMEX	Fair Value at December 31, 2009 (in thousands)
	Oil (Bbls)	Oil (Bbls)	$ per Bbl
1st Qtr 2010	9,500	28,500	$60.00-$81.50	$ (78)
2nd Qtr 2010	9,500	28,500	$60.00-$81.50	$ (174)
3rd Qtr 2010	9,500	28,500	$60.00-$81.50	$ (228)
4th Qtr 2010	9,500	28,500	$60.00-$81.50	$ (268)
1st Qtr 2011	7,375	22,125	$60.00-$81.50	$ (231)
2nd Qtr 2011	7,375	22,125	$60.00-$81.50	$ (248)
3rd Qtr 2011	7,375	7,375	$60.00-$81.50	$ (86)
				$ (1,313)

			Current Liability	$ (748)
			Non-current Liability	$ (565)

F-25

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The Fair Value amounts noted in the above table are based on valuations provided by Macquarie. Management has engaged Risked Revenue Energy Associates to perform an independent valuation which confirmed the amounts provided by Macquarie. The Company records changes in the unrealized derivative asset or liability as an unrealized gain or loss in the Consolidated Statements of Operations.

Through December 31, 2009, no settlement payment has been required under the agreement as WTI NYMEX prices through that date remained within the collar.

14. Asset Retirement Obligation

The Company follows the requirements of FASB ASC 410, “Asset Retirement Obligations and Environmental Obligations”. Among other things, FASB ASC 410 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. 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%, when the original liability was recognized. In 2009, the retirement obligation for the Albers #2 SWD was recognized using the current credit adjusted risk free rate of 8%. The Company used an estimated useful life of wells ranging from 30-40 years and an estimated plugging and abandonment cost of $5,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.

The following is a roll-forward of activity impacting the asset retirement obligation for the years ended December 31, 2008 and 2009: (in thousands):

Balance December 31, 2007	$ 531

Accretion expense	155
Liabilities settled	(30)
Balance December 31, 2008	$ 656

Accretion expense	48
Liabilities incurred	2
Revisions in estimated liabilities	(256)
Balance December 31, 2009	$ 450

The liabilities incurred relate to the Albers #2 SWD. The revisions in estimated liabilities resulted primarily from reducing the estimated plugging and abandonment costs for the Kansas properties from $10,000 per well to $5,000 per well.

F-26

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

15. 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 7,000,000. The most recent amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held on June 2, 2008. Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. Furthermore, 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 2009, 2008, and 2007 is summarized below:

	2009		2008		2007
	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price	Shares	Weighted Average Exercise Price
Outstanding, beginning of year	2,931,000	$0.38	2,441,000	$0.30	2,596,000	$0.31
Granted	500,000	$0.54	500,000	$0.74	-	-
Exercised	(410,000)	$0.27	(10,000)	$0.27	(126,000)	$0.42
Expired/cancelled	-	-	-	-	(29,000)	$0.64
Outstanding end of year	3,021,000	$0.42	2,931,000	$0.38	2,441,000	$0.30

F-27

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The following table summarizes information about stock options outstanding and exercisable at December 31, 2009:

Weighted Average Exercise Price	Options Outstanding (shares)	Weighted Average Remaining Contractual Life (years)	Options Exercisable (shares)
$0.27	1,831,000	0.3	1,831,000
$0.58	110,000	1.1	110,000
$0.81	80,000	2.0	80,000
$0.57	400,000	3.1	160,000
$1.44	100,000	3.4	100,000
$0.70	100,000	4.0	100,000
$0.50	400,000	5.7	-
	3,021,000		2,381,000

During 2009, the Company issued options to purchase 25,000 shares at $0.70 per share to each of the non-executive directors. These options vested upon grant date (January 8, 2009) and expire January 7, 2014. In addition, the Company issued options to purchase 400,000 shares at $0.50 per share to Michael J. Rugen, Chief Financial Officer. The options were issued on September 28, 2009. The options will vest over a five year period and will expire on September 27, 2015. Also during 2009, Mark A. Ruth, former Chief Financial Officer, exercised 400,000 options at $0.27 per share.

The weighted average fair value per share of options granted in 2008 and 2009 range from $0.39 to $1.06, calculated using the Black Scholes option pricing model.

Compensation expense related to stock options was $0.2 million in 2009 and 2008 and $0.1 million in 2007. At December 31, 2009, there was $0.2 million of total unrecognized compensation costs related to unvested options that is expected to be recognized over a weighted average period of approximately 2.1 years.

The fair value of stock options used to compute share based compensation is the estimated present value at grant date using the Black Scholes option pricing model with the following weighted average assumptions for 2008 and 2009: expected volatility of 100%, a risk free interest rate of 3.67% and an expected option life remaining from 0.3 to 5.7 years.

On February 8, 2010, the Company issued options to purchase 25,000 common shares at $0.43 per share to each of the non-executive directors. These options vested upon grant date and will expire February 7, 2015.

F-28

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

16. Income Taxes

The Company had no taxable income for the year ended December 31, 2009, but had taxable income for the years ended December 31, 2008 and 2007.

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: (in thousands)

	December 31,
	2009	2008	2007
Statutory rate	34%	34%	34%
Tax (benefit)/ expense at statutory rate	$(744)	$(2,323)	$ 480
State income tax expense	142	197	140
Impairment write-down not deductible for tax purposes	-	3,947	-
Unrealized loss on derivatives not deductible for tax purposes	446	-	-
Excess tax depreciation	(75)	(65)	(85)
Other	62	(132)	3
Utilization of NOL carry-forward	-	(1,624)	(538)
Net Change in deferred tax asset valuation allowance	(169)	(7,001)	(2,100)
Total income tax provision (benefit)	$(169)	$(7,001)	$(2,100)

Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements as required by ASC 740. The Company does not believe that any of its positions it has taken will not prevail on a more likely than not basis. As such no disclosure of such positions was deemed necessary. Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income. The Company has had recurring taxable income for its last three fiscal years. As of January 1, 2009, the Company had available approximately $15.5 million of net operating loss carry forwards to offset future taxable income.

During the year ended December 31, 2009, Management, using the “more likely than not” criteria for recognition, elected to recognize a deferred tax asset of $0.2 million. The recognition of the deferred tax asset in 2009 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 $0.2 million current income tax benefit (fully offset by the current provision related to 2009 taxable income) and $9.1 million.

At December 31, 2009, the deferred tax asset balance is $9.3 million. At December 31, 2008, the deferred tax asset balance was $9.1 million. The Company recorded an additional $3.9 million deferred tax benefit as a result of the $11.6 million ceiling test write-down. The recognition of the deferred tax asset will provide a better matching of income tax expense with taxable income in future periods.

F-29

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

As of December 31, 2009, the Company had net operating loss carry forwards of approximately $15.5 million which will expire between 2011 and 2023 if not utilized. Our open tax years include all returns filed for 2006 and later.

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

(in thousands)

	Year Ended December 31,
	2009	2008	2007
Deferred tax assets:
Net operating loss carry-forward	$ 5,982	$ 6,015	$ 7,314
Capital loss carry-forward	263	263	263
Excess of tax over book basis of oil and gas properties	4,334	3,947	-
Total deferred tax assets	$10,579	$10,225	$ 7,577
Deferred tax liability
Basis difference in pipeline	$ 1,309	$ 1,124	$ 1,209
Total deferred liability	1,309	1,124	1,209
Total net deferred taxes	$ 9,270	$ 9,101	$ 6,368
Valuation allowance	-	-	(4,268)
Net deferred tax asset	$ 9,270	$ 9,101	$ 2,100

17. Supplemental Cash Flow Information

The Company paid approximately $0.6 million, $0.4 million, and $0.3 million, for interest in 2009, 2008, and 2007 respectively. No interest was capitalized in 2009, 2008, or 2007.

18. 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 Unites 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 and contribute 150,000 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 expired on September 12, 2008.

F-30

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

19. Bank Debt

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 are 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 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’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.

On June 2, 2008, the Company entered into an amendment to its credit facility with Sovereign whereby the Company’s borrowing base was raised by Sovereign as a result of its review of the Company’s currently owned producing properties. The borrowing base was raised to $11 million effective June 2, 2008. The amendment also set the interest rate to the greater of prime plus 0.25% or 6% per annum. The Company had previously utilized about $4.2 million of the facility, leaving approximately $6.8 million then available for use by the Company upon this borrowing base increase. The Company used $5.35 million of the then available $6.8 million for the purchase of the Riffe Field properties in Kansas.

On February 5, 2009, the Company amended its credit facility with Sovereign to provide for a monthly reduction of the Bank’s commitment by $0.15 million per month for the five month period of February through June 2009. This commitment reduction is not a cash payment obligation of the Company but has the effect of reducing the Company’s available borrowing base in monthly increments of $0.15 million so that by June 2009 the Company’s available borrowing base under the Sovereign facility was to be reduced by $0.75 million from $11.0 million to $10.25 million.

On July 9, 2009, the Company’s borrowing base was increased from $10.25 million to $11.0 million under the revolving senior credit facility between the Company and Sovereign. The Company’s borrowing base was increased on the completion of the regular semiannual borrowing base review by Sovereign. The $11.0 million borrowing base is again made subject to a monthly available-credit reduction of $0.15 million per month beginning August 5, 2009, so that by the time of the next regular borrowing base review in six months, the borrowing base will again be $10.25 million.

As of September 30, 2009, the Company was out of compliance on the Leverage Ratio and Interest Coverage Ratio covenants under the credit facility. The Company was in compliance with the remaining financial covenants under the credit facility. The noncompliance occurred primarily as a result of the low commodity prices in the last quarter of 2008 and first and second quarters of 2009 that are included in the covenant compliance calculations. The Company has received a waiver from Sovereign Bank for noncompliance of these covenants for the quarter ended September 30, 2009. There can be no assurances that Sovereign Bank will waive noncompliance of covenants should future instances occur.

F-31

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

On February 23, 2010, the Company entered into an amendment to its credit facility with Sovereign. This amendment increased the borrowing base from $10.25 million to $11.0 million as a result of the completion of the semiannual borrowing base review by Sovereign. The amendment also reduced the monthly commitment reduction from $0.15 million to $0.1 million. The amendment also changed the maturity date to June 30, 2011. In addition, the amendment modified the covenant compliance calculations. This modification allowed the Company to exclude the first and second quarters of 2009. As of December 31, 2009, the Company was in compliance with all covenants. The next borrowing base review will take place in June 2010.

The total borrowing by the Company under the facility at December 31, 2008 and 2009 was $9.9 million.

20. Methane Project

F-32

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

MMC declared startup of commercial operations on April 1, 2009. During the month of April, the facility produced and sold 14 MMcf of methane gas to Eastman and was online about 91% of the calendar month. System maintenance and landfill supply adjustments accounted for the remainder of the time. On May 1, 2009, Eastman advised MMC that it was suspending deliveries of the methane gas stream pending approval by the federal Environmental Protection Agency (“EPA”) of Eastman’s petition for inclusion of treated methane gas as natural gas within the meaning of the EPA’s continuous emission monitoring rules applicable to Eastman’s large boilers during the annual “smog season” beginning May 1 of each year. Although Eastman had begun seeking this approval in February, 2009, with the assistance of the Air Quality Department of the Tennessee Department of Environment and Conservation, the EPA had not acted by May 1. Eastman furnished to the EPA information provided by MMC that establishes that the methane gas stream is better fuel under the rule standards than even “natural” gas, which is technically defined in the smog season rules to include gas being “found in geologic formations beneath the earth’s surface”. Methane sales to Eastman were intended to resume upon EPA’s formal approval of Eastman’s petition or expansion of the regulatory definition, or both. However, as of December 31, 2009 neither of these actions has been taken by EPA, despite the existence of EPA’s own established agency initiative, the Landfill Methane Outreach Program, which is intended to encourage beneficial use of the methane component of raw landfill gas. Because approval was not received, MMC was forced to seek alternative markets for the methane gas stream.

F-33

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The agreed contract price of over $6 per MMBtu was a premium to the then current five-year strip price for natural gas on the NYMEX futures market. MMC’s plant is capable of producing a daily average of about 400 Mcfd of methane from the Carter Valley landfill at current raw gas volumes. However, daily production during September and October 2009 at MMC’s facility was intermittent due to a combination of temporary factors. Average daily production for September and October 2009 was 248 Mcfd on the twenty days the plant was in production. In November 2009, MMC’s average daily gas production on producing days was 288 Mcfd of sales methane and in December 2009, this amount was 293 Mcfd of sales methane.

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program (the “Program”), pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. The revenues from the Methane Project received by Hoactzin are to 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 could accelerate reaching the Payout Point. As stated above, the Purchase 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 million of equipment required for the Methane Project, or about 22% 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.

21. 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.

F-34

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

22. Quarterly Data and Share Information (unaudited)

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

(In thousands, except per share data)

Fiscal Year Ended 2009	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr
Revenues	$ 1,900	$ 2,355	$ 2,585	$ 2,891
Net loss	(402)	(81)	(449)	(1,086)
Net loss attributable to common shareholders	(402)	(81)	(449)	(1,086)
Loss per common share	$ (0.01)	$ (0.00)	$ (0.01)	$ (0.02)

Fiscal Year Ended 2008	1st Qtr	2nd Qtr	3rd Qtr	4th Qtr
Revenues	$ 3,306	$ 4,634	$ 5,067	$ 2,594
Net income (loss)	5,812	1,422	1,563	(8,627)
Net income (loss) attributable to common shareholders	5,812	1,422	1,563	(8,627)
Income (loss) per common share	$ 0.10	$ 0.02	$ 0.03	$ (0.14)

During the first quarter of 2008, the Company recorded a $5.2 million deferred tax asset. During the fourth quarter of 2008 the Company recorded a $11.6 million ceiling test write-down.

23. 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 reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were located in the United States.

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2009 and 2008 (in thousands):

	Years Ended December 31,
	2009	2008
Proved oil and gas properties	$ 24,182	$ 23,031
Unproved properties	109	1,243
Total proved and unproved oil and gas properties	$ 24,291	$ 24,274

Less accumulate depreciation, depletion and amortization	11,931	10,132
Net oil and gas properties	$ 12,360	$ 14,142

F-35

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Oil and Gas Related Costs

The following table sets forth information concerning costs incurred related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands):

	Years Ended December 31,
	2009	2008	2007
Property acquisitions proved	$ -	$ 5,350	$ 200
Property acquisitions unproved	-	-	-
Exploration cost	-	-	-
Development cost	1,020	6,614	4,991
Total	$ 1,020	$ 11,964	$ 5,191

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. (in thousands)

	Year Ended December 31,
	2009	2008	2007

Revenues	$ 9,711	$15,570	$ 9,300
Production costs and taxes	(5,225)	(5,731)	(4,160)
Depreciation, depletion and amortization	(1,800)	(1,374)	(835)
Income from oil and gas producing activities	$ 2,686	$ 8,465	$ 4,305

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

F-36

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Estimated Quantities of Oil and Gas Reserves

The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2009, 2008 and 2007.

	Oil (MBbls)	Gas (MMcf)	MBOE

Proved reserves at December 31, 2006	1,712	1,307	1,930
Revisions of previous estimates	700	(46)	692
Improved recovery	19	-	19
Purchase of reserves in place	16	-	16
Extensions and discoveries	14	-	14
Production	(185)	(127)	(206)
Sales of reserves in place	-	-	-

Proved reserves at December 31, 2007	2,276	1,134	2,465
Revisions of previous estimates	(1,313)	(120)	(1,333)
Improved recovery	59	-	59
Purchase of reserves in place	234	-	234
Extensions and discoveries	154	-	154
Production	(162)	(104)	(180)
Sales of reserves in place	-	-

Proved reserves at December 31, 2008	1,248	910	1,399
Revisions of previous estimates	1,203	(721)	1,084
Improved recovery	-	-	-
Purchase of reserves in place	-	-	-
Extensions and discoveries	-	-	-
Production	(171)	(73)	(183)
Sales of reserves in place	(7)	--	(7)

Proved reserves at December 31, 2009	2,273	116	2,293

Proved developed reserves at:
December 31, 2007	1,605	1,131	1,793
December 31, 2008	1,240	907	1,391
December 31, 2009	1,579	116	1,598

F-37

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

(amounts in thousands)	Year Ended 12/31/09			Year Ended 12/31/08			Year Ended 12/31/07
	Oil	Gas	Total	Oil	Gas	Total	Oil	Gas	Total
Total proved reserves year-end reserve report	$27,964	223	$28,187	$9,177	1,116	$10,293	$52,117	1,510	$53,627

Proved developed producing reserves (PDP)	$15,476	223	$15,699	$9,020	1,114	$10,134	$36,319	1,485	$37,804
% of PDP reserves to total proved reserves	55%	1%	56%	87%	11%	98%	67%	3%	70%

Proved developed non-producing reserves	$5,185	-	$5,185	$157	2	$159	$441	25	$466
% of PDNP reserves to total proved reserves	18%	-	18%	2%	-	2%	1%	-	1%

Proved undeveloped reserves (PUD)	$7,303	-	$7,303	-	-	-	$15,357	-	$15,357
% of PUD reserves to total proved reserves	26%	-	26%	-	-	-	29%	-	29%

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 table: (in thousands):


	December 31,
	2009	2008	2007
Future cash inflows	$ 122,844	$ 51,388	$ 206,276
Future production costs and taxes	(56,550)	(36,491)	(76,944)
Future development costs	(11,039)	(309)	(10,175)
Future income tax expenses	-	-	-
Net future cash flows	55,255	14,588	119,157
Discount at 10% for timing of cash flows	(27,068)	(4,295)	(65,530)
Discounted future net cash flows from proved reserves	$ 28,187	$ 10,293	$ 53,627

F-38

Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands):

	December 31,
	2009	2008	2007
Balance, beginning of year	$10,293	$53,627	$26,469
Sales, net of production costs and taxes	(4,486)	(9,839)	(5,140)
Discoveries and extensions, net of costs	-	1,492	1,166
Purchase of reserves in place	-	1,642	568
Sale of reserves in place	(109)	-	-
Net changes in prices and production costs	10,433	(30,890)	16,893
Revisions of quantity estimates	17,705	(9,373)	16,584
Accretion of discount	1,029	1,029	2,647
Net change in income taxes	-	-	-
Previously estimated development cost incurred during the year	28	-	-
Changes in future development costs	(5,489)	3,251	(5,669)
Changes in production rates and other	(1,217)	(646)	109
Balance, end of year	$28,187	$10,293	$53,627

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 cost (less salvage value) necessary to produce such reserves. The prices used for December 31, 2009, 2008 and 2007 were $53.81, $33.96, and $85.44, per barrel of oil and $4.61, $7.76, and $7.21 per MCF of gas, respectively. The Company’s proved reserves as of December 31, 2009 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2009. The Company’s proved reserves as of December 31, 2008 and 2007 were measured by using end of year prices. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

F-39