CORRESP 1 filename1.htm

Tengasco, Inc.
10215 Technology Drive, Suite 301
Knoxville, TN 37932-4307
865.675.1554
865.675.1621 (facsimile)

January 14, 2008

Mr. Karl Hiller
Branch Chief, Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D. C. 20549

VIA EDGAR FILING

Re: Tengasco, Inc.
Form 10-K for the Fiscal Year Ended December 31, 2006 Filed March 30, 2007
Form 10-Q for the Quarter Ended September 30, 2007
File No. 1-15555

Dear Mr. Hiller:

Tengasco, Inc. hereby responds as follows to each of the six numbered items in your letter dated December 7, 2007. The December 7 Letter refers to certain “PRIOR COMMENTS” contained in a letter dated October 2, 2007 and our written responses. This letter refers both to your numbered comments as of Dec. 7, and the prior comment to which your December 7 comments are directed. Incidentally, we note that your comment number 3 in the December 7 letter addresses our third quarter 2007 Form 10-Q which was not the subject of any comment in your October 2 letter. That comment number 3 is the only comment in the December 7 letter addressing that Form 10-Q.

We believe that disclosure needed for sound investment decisions was in fact made in our original filings of our Form 10-K for the year ending December 31, 2006 and Form 10-Q for the Quarter ended September 30, 2007. However, in order to enhance the disclosure made in our original filings, we remain willing to amend our Form 10-K and Form 10-Q as set out below and as may be further suggested following your consideration of our responses and the receipt of any additional comments you may have to these responses.

For your convenience, we include the text of each of your comments underlined for reference, together with our corresponding responses, below:

Your Comment No. 1 to PRIOR COMMENT NO. 2 Form 10-K for the Fiscal Year Ended December 31, 2006 Properties, page 21; Reserve Analyses, page 23

We have read your response to prior comment 2, regarding the non-GAAP disclosure requirements of Item 10(e) of Regulation S-K. You state that your table showing the standardized measure of discounted future net cash flows on page F-32 "...does not include values for the proven producing category but includes only volumes for that category." The guidance in paragraph 30 of SFAS 69 requires that you include cash flows (i.e. values) associated with all proved reserves (i.e. volumes), in computing the standardized measure of discounted future net cash flows.

Please explain how it is possible that you have included the volumes but no corresponding values for your producing properties in the table.

Since the PV-l0 measures described are not GAAP measures, you should include a tabular disclosure under this heading reconciling both non-GAAP measures to the most closely related GAAP measure. However, given that you have determined that you will incur zero taxes for all future production of current reserves, we do not see the point of describing the measure that reflects development and production of all reserves as PV-l0, since it does not differ from the GAAP measure. Please label GAAP measures with GAAP terminology. You may discuss how your particular measure relates to a PV-10 measure if you believe this would be meaningful.

As for the non-GAAP measure related to your producing properties, please show the portion of your standardized measure of discounted future net cash flows that is attributable to non-producing properties as a reconciling item. Also disclose with your reconciliation the assumptions you have made about the timing of future development and production, and your reasons for focusing on currently producing properties.

OUR RESPONSE: We believe that all of the substance of your comment is resolved by insertion of the following table which provides the values of the categories of proved reserves, both as to oil and as to gas, for each of the past three years. This table will be included by amendment on page 23 of the Form 10-K. Any PV₁₀ measures would be the same as GAAP measures because there are no reconciling items.

TENGASCO, INC.
RESERVE Value ANALYSIS 2004-2006


	Year Ended 12/31/04			Year Ended 12/31/05			Year Ended 12/31/06
	Oil	Gas	Total	Oil	Gas	Total	Oil	Gas	Total

Total proved reserves year-end reserve report	$12,073	$14,658	$26,731	$23,530	$13,649	$37,179	$23,606	$2,863	$26,469

Proved developed producing reserves (PDP)	$8,630	$9,814	$18,444	$18,721	$8,048	$26,769	$18,922	$2,783	$21,705
% of PDP reserves to total proved reserves	32%	37%	69%	50%	22%	72%	71%	11%	82%

Proved developed non-producing reserves	$1,046	$3,498	$4,544	$1,602	$3,603	$5,205	$449	$80	$529
% of PDNP and PBP reserves to total proved reserves	4%	13%	17%	4%	10%	14%	2%	0%	2%

Proved undeveloped reserves (PUD)	$2,397	$1,346	$3,743	$3,207	$1,998	$5,205	$4,235	$0	$4,235
% of PUD reserves to total proved reserves	9%	5%	14%	9%	5%	14%	16%	0%	16%

Your Comment No. 2 to Prior Comment No. 3. Financial Statements; Note 1- Summary of Significant Accounting Policies, page F-9 Inventory, page F-10

We note your response to prior comment 3, indicating that prior to 2006 you were unable to keep track of your costs of inventory, and had therefore decided to report crude oil inventory at market value. Tell us why your internal controls have not allowed for accounting of inventory at actual costs; and explain your basis for concluding that your internal controls were effective, given this limitation. Submit a rollforward of your crude oil inventory showing all changes in quantities for each period, and the balances at each reporting date, covering the last three years and subsequent interim period. Include the values ascribed to each change depicted in the table, describe the source of all such valuations, and provide your materiality calculations.

OUR RESPONSE:

The following table displays inventory levels for the last three years along with the market price used for valuation of the inventory. Inventory consists of crude oil in tanks awaiting pickup by the purchaser of production. (Typically any such inventory at period end is picked up for purchase within the first ten days of the subsequent period at posted market prices.)

Prior to 2006 the Company had both natural gas production and oil production in Kansas. Several costs relating to both oil and gas production were comingled between the two product types. In order to determine an accurate separate cost for its oil production, the Company would have had to create an accounting system to allocate employees’ time and expenses between the oil or gas product types. The Company determined there was no management value to such a system. The total cost for Kansas oil and gas production was captured correctly. Currently these costs are not commingled. The fact that the Company did not require an allocation between costs for product types neither causes nor demonstrates any weakness in internal controls.

In determining whether our internal controls are effective, we consider whether there are deficiencies in the design or operation of our internal controls such that there is a reasonable possibility that a material misstatement in our annual or interim consolidated financial statements will not be prevented or detected. As discussed below, our assessment is that any misstatements in our prior annual and interim consolidated financial statements as a result of our accounting for crude inventory at market is immaterial.

We estimate that if a cost for crude oil in inventory had been calculated during these periods when the Company had two product types, such cost during those periods would have been in the range of approximately $50.00 per barrel when all direct costs and overhead are considered. On this assumption, the most that the inventory could have ever been overstated by using market prices would be $118,000 or $.0020 per share for the quarter ending June 30, 2006 as indicated in the table. That amount, and all lesser amounts for other reporting periods, are clearly immaterial. At no time during the history of the Company has the apparent difference between market price and anticipated cost (if calculated) of unsold crude in tanks for a short period before sale been a material difference.

QUARTE R ENDING	12/31/2004	3/31/2005	6/30/2005	9/30/2005	12/31/2005	3/31/2006	6/30/2006	9/30/2006	12/31/2006

Inventory Bbls	8262.7	8262.7	8013.2	8013.2	8934.9	8124.9	7723	7710.4	9728.3
Market Price used ($)	41.36	41.36	53.09	53.09	55.55	57.81	65.27	58.63	56.59
Value ($)	341,745	341,745	425,423	425,423	496,331	469,701	504,093	452,059	550,522
Total Assets	29,209,749	26,395,380	25,945,516	25,421,851	28,908,616	25,810,581	26,379,921	28,110,673	28,454,338
Overstatement as a % of Total Assets	N/A	N/A	0.0010	0.0010	0.0017	0.0025	0.0045	0.0024	0.0023
Weighted Average Number of Shares OS	40,855,972	48,756,977	48,677,828	49,750,556	52,019,051	58,605,109	58,715,015	58,802,166	58,851,883
Value of Inventory at Market Price per share ($)	0.0017	0.0015	0.0005	.0005	0.0010	0.001	0.0020	0.0011	0.0011
Overstate-ment of Inventory at Market Price comparedto $50 as COST	N/A because market was lower than Cost	N/A because market was lower than Cost	24,761	24,761	49,589	63,455	117,930	66,541	64,109

Form 10-Q for the Fiscal Quarter Ended September 30, 2007

Financial Statements Note 5- Related Party Transactions, page 10

We note you entered into a drilling program on September 17, 2007 with Hoactzin Partners, LP for ten wells to be drilled in Kansas. We understand that Hoactzin will receive all the working interest in the ten wells, plus a 75% net profits interest in a methane extraction project, in exchange for a stipulated amount per well, dependent upon whether it is a productive or non-productive well.

We also understand that Hoactzin has the option to exchange up to 20% of its net profits interest in your subsidiary's methane extraction project for shares of your convertible preferred stock if the drilling program and methane project together fail to return net revenues equal to 25% of the actual drilling program purchase price by December 31, 2009; and that there are similar options covering each subsequent year.

Please expand your disclosure to include details about and to discuss your obligations under the drilling program and the methane extraction project. Also disclose the accounting you will apply to this arrangement, including Hoactzin's conversion right. In preparing your disclosures, please be sure to address the following points.

Disclose the nature and status of the methane extraction project, amount of funding, time and steps necessary to complete the project, your interests in any related property, and the manner by which revenues will be generated.

Disclose the extent of your responsibilities for completing the ten well drilling program, when you plan to drill each well, your expectations about the costs you will incur, and the timing of proceeds to be received from Hoactzin. Disclose the amount of funding you have received from Hoactzin as of the balance sheet date, and your handling of these amounts in the accounts. Since you have guaranteed performance of any productive wells and the methane extraction project, in terms of the purchase price, it should be clear how you will account for the funds received pending resolution of this uncertainty.

Disclose the amount of funding you have received from Hoactzin as of the balance sheet date, and your handling of these amounts in the accounts. Since you have guaranteed performance of any productive wells and the methane extraction project, in terms of the purchase price, it should be clear how you will account for the funds received pending resolution of this uncertainty.

Disclose the amounts you have capitalized for the properties associated with the ten well drilling program and the methane extraction project.

Disclose the terms of the convertible preferred shares that may become issuable under the arrangement, including the conversion price and number of common or other shares into which they are convertible, conditions under which conversion may be elected or required, and the manner of determining the liquidation value for each successive conversion option and its significance in conversion.

Disclose the manner by which you will report management fees received under this arrangement, and your rationale for the policy described.

We urge you to consider the guidance in Rule 4-10(c)(6) of Regulation S-X, as it relates to property conveyances, drilling arrangements, and fees received for services. It should be clear from your response and the disclosures you propose, how you have applied this guidance in formulating your accounting methodology. Since the funds from Hoactzin may ultimately result in the issuance of convertible preferred shares, please be sure to explain how this potential equity characterization is captured in your methodology.

OUR RESPONSE:

The Company proposes adding additional language to the referenced portion of the Form 10-Q beginning at page 11 so that the provisions beginning there and continuing to the end of this section read as set out beginning in the fourth paragraph of this response.

The management fee will be reported as a separate line item on the Company’s income statement. Although this fee is referred to as a management fee, as is defined in the agreements it is in the nature of a net

profits interest.

The Company intends that funds received for drilling program interests will be treated as offset to oil and gas properties; that net profits interests received from the methane project will be reported as line items on the Company’s income statement; and that until circumstances arise or become probable triggering any ability to require the Company to exchange Hoactzin’s net profits interest in the methane project for preferred stock to be issued, no accounting adjustment will be made for any obligation under that exchange agreement. The Company’s position is that it is not justified in doing otherwise in view of the conditional nature of an option for future exchange of Hoactzin’s net profits interest in the methane project for convertible preferred stock and the additional facts that neither the amount of preferred stock, nor the liquidation value of any preferred stock, nor the conversion option price can be determined or estimated until the factors triggering any issuance of preferred stock may occur, which the Company views as being highly unlikely.

As noted, we would amend to add the following beginning at current page 11, complete paragraph number 1 on that page to read as follows:

“On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, LP (“Hoactzin”) for ten wells to be drilled in Kansas targeting production of oil during the remainder of 2007. Under the drilling program, Hoactzin will pay $400,000 per well completed as a producer, and $250,000 per drilled well that is nonproductive. The total purchase price will consequently be between $2.5 million and $4 million. The controlling person of Hoactzin is Peter E. Salas, the Chairman of the Company’s Board of Directors and also the controlling person of Dolphin Offshore Partners, LP, the Company’s largest shareholder. On September 17, 2007 the Audit Committee of the Company’s Board of Directors, as well as the Board of Directors, authorized the transactions in accordance with the Company’s related party transaction policy.

Under the terms of the drilling program, Hoactzin will receive all the working interest in the ten wells, 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 above is in the nature of a net profits interest. The fee paid by Hoactzin will increase to 85% of working interest revenues when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price paid for the drilling program. The Company’s lenders have agreed to consider the fee as an equivalent value to a working interest for purposes of calculating the Company’s borrowing base.

The Company is obligated under the terms of the drilling program to drill ten wells, consisting of approximately three wildcat wells and seven developmental wells on it properties in Kansas. The Company agreed to attempt to drill these ten wells by year end 2007 but if not able to do so to drill them as soon as possible in 2008. To date of this amended report (January ___, 2008) nine of the wells have been drilled and the tenth well is to be drilled in January. Of the nine drilled wells, 8 have been completed as producers and a producing currently approximately 84 barrels per day in total. Although that production level will decline with time in accordance with expected decline curves for this type of well, the results of drilling are expected at current prices and expected production volumes to result in the agreed payout point being reached sometime in the year 2013. (Any revenues contributed by the methane project as described below would serve to accelerate that point to an earlier date.) As of September 30, 2007 Hoactzin had paid $1,300,000 for its interest in the drilling program, and to date of this amended report, Hoactzin has paid $3,850,000 for its interest in this drilling program. All obligations of Hoactzin have been paid at or near the time of drilling and the last well drilling costs have been paid in advance. The Company will account for funds received for interests in the drilling program as an offset to oil and gas properties. The Company expects based on its experience in Kansas drilling and completion of oil wells that the payment of Hoactzin’s purchase price for the ten wells in the drilling program will exceed costs incurred by the Company in drilling and completing all program wells by approximately $1 million, and this expectation has been met as to each of the nine program wells that have been drilled, or drilled and completed, to date.

On September 17, 2007 Hoactzin was simultaneously conveyed a 75% net profits interest in the Company’s subsidiary Manufactured Methane Corporation’s (“MMC’s) Carter Valley, Tennessee methane extraction project. When the methane project comes online, the methane project revenues received by Hoactzin will also apply towards the determination of the payout point for the drilling program. When the payout point is reached from either the drilled wells or the methane project or a combination thereof, Hoactzin’s net profits interest in this methane project will decrease to a 7.5% net profits interest. The Company believes that the addition of revenues of the methane project to reaching the payout point of the drilling program as a favorable provision that is anticipated to both to rapidly accelerate reaching that payout point with the Company’s and providing additional safeguard of obviating any need to issue preferred stock in the Company as set out below. The grant of a 7.5% net profits interest in the methane project following the payout point of the drilling program being reached is also considered a favorable provision because the Company has used funds provided by Hoactzin for purchase of its interests in the drilling program above drilling program costs as experienced, for the purchase of approximately $1,000,000 in equipment required for the methane project, or about 25% of the project’s capital costs. The availability of these funds has avoided the need to borrow those funds, and to both pay interest to any lending institution or to dedicate project revenues to debt service.

The Company’s wholly owned subsidiary, Manufactured Methane Corporation, has placed equipment orders for its first stage of process equipment (cleanup and carbon dioxide removal) and the second stage of process equipment (nitrogen rejection) as of the date of this amended Report, the Company has paid and capitalized approximately $1,875,000 in equipment costs for this project from the Company’s cash flow from operations including the proceeds of the sale of the drilling program interests to Hoactzin as have exceeded drilling and completion costs of the program wells. Total project costs, including pipeline construction, are expected to be approximately $4.1 million including costs for compression and interstage controls. The Company anticipates that equipment will be manufactured and delivered to allow operations to begin in the April or May 2008 time period when equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company under the terms of the Company’s existing natural gas purchase and sale agreement. The Company anticipates approximately 400 MCF per day of sales gas to be generated at current volumes of gas collected by Allied Waste at the Carter Valley location.

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

The Company also announced that on September 17, 2007 it entered into an additional agreement with Hoactzin providing that if the new drilling program wells and the methane project interest in combination failed to return net revenues to Hoactzin equal to 25% of the actual drilling program purchase price by December 31, 2009, then Hoactzin has 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 drilling program 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 American Stock Exchange. Hoactzin has a similar option each year after 2009 in which Hoactzin’s then-unrecovered investment 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.

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 impossible in view of the success of the drilling program), then Hoactzin would have an option to exchange 20% of its methane project interest in 2010 and each of 4 year thereafter for preferred stock with liquidation value of 100% of its drilling program investment (not 135%) convertible at five different levels being the trailing average price before each year’s issuance of the preferred. The maximum number of common shares into which all such preferred could be converted cannot be calculated given the formulaic determination of conversion price based on future stock price. However, assuming for purposes of a calculation example only, a uniform stock price of $.75 per share, the preferred stock would be convertible (at investment $3.7 million for eight of ten producing wells) or 4.93 million common shares, approximately 8.35% of the Company’s currently outstanding shares as of the date of this amended report. The exchange agreement also includes a cap on the number of

However, the Company anticipates that with the demonstrated successful results of the first nine wells of the drilling program that the payout of 25% of the actual drilling program price will be reached by December 31, 2009 and no requirement to issue preferred stock will arise in 2010. The Company further anticipates that at current oil and gas prices, and at currently expected sales levels of methane gas from MMC’s project to come online in 2008, that the balance of the unrecovered investment by Hoactzin will also be reduced by at least 20% each year thereafter. Based only on current production from the eight producing wells (i.e. not considering any revenue contribution from the methane project), expected decline curves for production, and using current oil prices, the Company expects that by December 2009, Hoactzin will have received 66% of its investment, far in excess of the 25% required in order to obviate any occasion to exchange its methane interest for preferred stock. As a result, 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.

Engineering Comments Risk Factors page 15. We have reviewed your response to prior comment seven, concerning the risk of reserve revisions. You indicate that a portion of the negative reserve revision was due to 1) sale of properties and 2) the removal of quantities in the PUD and PDNP reserve classifications. Revisions of estimated reserves do not include acquisitions or sales of reserves, and are therefore not appropriately covered by a risk factor about revisions. This term is defined in paragraph 11(a) of SFAS 69 as being a change in a previous estimate of proved reserves that is attributable to new information, generally related to development drilling, production history and economic factors. The suggested risk factor in our prior comment was based on your history of negative reserve estimate revisions, which appear to have been due to poorer than expected performance in some instances. The risk of not finding or acquiring new reserves is a completely different issue which should be addressed separately. We reissue prior comment seven. [PRIOR COMMENT SEVEN READS AS FOLLOWS: Please include a risk factor discussing the possibility that reserve estimates may be subject to material downward revisions. We expect this would appropriately clarify that you have revised your gas reserves downward by almost 70% in the last three years; and address the implications of this on your current and future results of operations.]

OUR RESPONSE:

We propose including the following at page 18 following the 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”:

The Company’s Reserve Estimates May Be Subject To 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.” Not only are the future estimates of net cash flows from the Company’s proved reserves and their present value 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 over time to be correct, may cause the Company to make drilling or developmental decisions causing some or all of the Company’s proved reserves to be removed from time to time from the proved reserve categories previously reported by the Company. This may occur because economic expectations or forecasts, together with the Company’s limited resources, may cause the Company to determine that drilling or development 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 last three year period as a result of removal of portions of the Company’s reported gas reserves in the “proved undeveloped category (“PUD”) and the “proved developed nonproducing” (“PDNP”) categories because of the Company’s determination that additional drilling or development of those reserves may not occur in the foreseeable future based on the economic returns compared to the costs and anticipated results of any such activity. Although that particular revision 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.

Your Comment No. 5 to Prior Comment No. 8, Properties, Page 21.

We have reviewed your response to prior comment eight, regarding the disclosure requirements for principal (materially important) properties, and for properties which are of major significance. Based on our review of your reserve report, it appears that the Croffoot, Harrison A, Lewis and Kraus A leases may be appropriately considered principal properties. Therefore, disclosure about your Kansas properties should include specific information pertaining to these properties. If you do not have properties of major significance, more detailed information and maps for those properties would not be required. However, information about production, reserves, locations, development and the nature of your interest is required for your principal (materially important) properties, regardless of whether these are also of major significance. Please revise your document to comply with Instruction 3 of Item 102 of Regulation S-K.

OUR RESPONSE: We propose to add by amendment the following information in response to this comment:

	Oil in total barrels for the year (Warren Reed #2 is a Gas well)
	Total Oil Production 2006			189,189 Barrels
	LEASE	2006 Gross Production barrels	Company Net Working Interest	Company Net royalty Interest	Percentage of Total Production
	Top KS Leases Productivity
1	Croffoot B	10171	100%	82.1%	5.3%
2	Harrison A	17193	100%	87.5%	9.1%
3	Lewis	6174	100%	87.5%	3.2%
4	Dirks	3993	100%	87.5%	2.1%
5	Kraus A	4773	100%	82.1%	2.5%
6	Croffoot	5040	100%	86.1%	2.6%

	Reserve Values in $1000's
	Total PV10			$26,469.19
	LEASE	Lease $PV10	PUD $PV10	Lease Total $PV10	Percentage of Total Reserves
	Top KS Reserve Leases
1	Croffoot B	$1557.40		$1,557.41	5.8% 6 producing wells
2	Harrison A	$1412.92		$1,412.93	5.3% 5 producing wells
3	Lewis	$874.73	$466.164	$1,340.89	5.0% 3 producing wells
4	Dirks	$782.73	$394.575	$1,177.31	4.4% 2 producing wells
5	Kraus A	$1072.08		$1,072.09	4.0% 4 producing wells
6	Croffoot	$839.67	$229.323	$1,069.00	4.0% 2 producing wells

Any PV₁₀ measures would be the same as GAAP measures because there are no reconciling items.

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 our ongoing interests in Kansas. By using 3-D seismic evaluation on existing locations owned by the Company in Kansas, we have added and continue to add proven direct offset locations. As a result of recent higher commodity prices for its oil, the Company has been able to drill from cash flow and attract very favorable drilling partner programs in which the Company retains not only a carried beginning interest but a higher-than-industry-standard revisionary interest. We expect to continue this mix of company drilling and program drilling depending primarily on future cash flow and future oil prices. Breaking down the Company’s assets into individual leases produces no apparent stand out leases that appear to be standalone 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, 2006:

Kansas accounted for 83% of the Company’s revenue (i.e. $7,497,000 of $9,001,681.)

Kansas accounted for 84.6% of the Company’s total production measured as BOE’s (Barrel of Oil Equivalents) (See chart page 25)

Tennessee accounted for just 15.3% of production

Kansas contributes $3.78 million dollar in value in future proven development locations as of yearend 2006, compared to just $150,000 in Tennessee

Focus in 2007 will be to continue with offset seismic development, and leasing activity in Kansas. As a result, our undeveloped location value and total number of locations are expected to grow.

[GRAPHIC

Your Comment No. 6 to Prior Comment No. 9. Supplemental Oil and Gas Information (Unaudited), page F-30; Oil and Gas Reserves, page F-31.

We have reviewed your response to prior comment nine, including the additional disclosure you have proposed. The text submitted appears to characterize all changes in your total reserve estimate as revisions, with subcategories. Since revisions are a separate category of change defined in paragraph 11(a) of SFAS 69, your disclosure should differentiate between revisions, as defined, and each of the other types of change identified in paragraph 1 1(a) through (f). For example, a sale of reserves, such as that which occurred in 2005, is a different category of a reserve change than a change in a prior reserve estimate (these generally result from new information attributable to development drilling, production history, and economic factors). Therefore, the explanations for the downward revision in gas reserves should not include the sale of reserves as part of the explanation of the revision line-item category. Any changes that are required to be reported on separate lines in the table should be accompanied by distinct explanations, as appropriate, when the changes depicted are significant. Please revise your proposed changes to have separate explanations of significant reserve changes for each lure--item category, consistent with the guidance in paragraph I I of SFAS 69.

OUR RESPONSE: We propose to amend to provide the following in response to this comment [the material to be inserted is located between the *** and ***]:

***

Oil and Gas Reserves (unaudited)

The following table sets forth the Company’s net proved oil and gas reserves at December 31, 2006, 2005 and 2004 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (Mcf) in the case of gas.

	Oil (bbls)*	Gas (Mcf)**

Balance, December 31, 2003	1,371,134	14,344,703
Revisions of previous estimates	(190,585)	(5,913,179)
Improved Recovery	-	-
Purchase of Reserves in Place	-	-
Extensions and Discoveries	41,054		-
Production	(131,603)		(484,524)
Sale of Reserves in Place

Balance, December 31, 2004	1,090,000		7,947,000
Revisions of previous estimates	175,285		(629,633)
Improved Recovery	79,600		-
Purchase of Reserves in Place
Extensions and Discoveries	174,130		-
Production	(144,552)		(204,128)
Sale of Reserves in Place	-		(2,350,000)

Proved reserves at December 31, 2005	1,374,463		4,763,239
Revisions of previous estimates	20,120		(3,318,074)
Improved recovery	110,460		-
Purchase of Reserves in Place
Extensions and Discoveries	396,152		-
Production	(189,189)		(138,078)

Sales of Reserves in Place	-		-
Proved reserves at December 31, 2006	1,712,006		1,307,087

*Oil

During the last two years, the Company has added to its proven oil reserves at year-end 2004 on existing properties in Kansas in four ways:

(1)

Revisions of previous estimates. This has resulted in significant upward changes to the total proved oil reserves. The higher end-of-year price point for the year ending December 31, 2005 compared to 2004 (p. F-34 paragraph 1) played a large role, resulting in 175,285 additional barrels of oil being added to reserves. In 2006 the still higher year end of year price point added an additional 20,120 barrels over 2005 levels. This occurred in each year because the higher price allowed the term of profitable well life to be extended in the Company’s reserve calculation, in view of the higher prices being able to exceed operating expenses for a longer period of time, thereby adding the volumes produced during that extended time to current reserves.

(2)

Improved Recovery. In both 2005 and 2006 the Company experienced increased cash flow from higher oil prices, permitting the Company to implement improved recovery techniques on its existing wells (for example, polymer treatments) which resulted in the addition of 79,600 barrels of new reserves that would not have occurred without the improved recovery in 2005, and 110,460 barrels in 2006.

(3)

Additional Wells. The Company increased its reserves by drilling additional wells. The Company drilled 7 gross development wells (p. 27) which added 25,768 barrels of oil in 2005. The Company drilled 10 more wells in 2006 which added another 80,000 barrels of reserve.

(4)

The Company implemented an aggressive 3D seismic program on existing properties that resulted in the addition of 148,362 barrels of oil in the “Proved-Undeveloped” category (“PUD”) in 2005. Some of that group were drilled in 2006 and similar additional PUD’s in 2006 were added as our acreage position and offset well control with 3D seismic increased, resulting in 316,152 barrels of additional total reserves. The time frame for this PUD development was forecast at the rate that could be drilled in one year from current cash flows. (Those PUDS for 2006, plus others have in fact been drilled in 2007.)

**Gas
Sales of reserves in place. In 2005 a sale of 2.35 BCF of reserves occurred (Kansas Gas Sale, monetary results are discussed on p. 34, footnoted on p. 26) impacting the 2005 gas reserves with the largest reduction in the Company’s gas reserves during that year.

In addition to the sale of 2.35 BCF of reserves, there have been sequential downward revisions of previous estimates in the Company’s gas reserves each year since 2004 as a result of multiple factors and events relating to the history of production from Swan Creek and changing economic factors in the oil and gas markets. In 2005 the Company also had a downward revision to the “proved developed nonproducing” category of reserves (“PDNP”) primarily in Swan Creek of 629,633 Mcf. This revision occurred because the Company did not intend to seek to recover the potential reserves behind pipe in existing Swan Creek gas wells because the potential return on such an investment return did not compare favorably to other options for the Company. The Company’s focus with the Company’s limited resources was drilling for oil in 2006 in Kansas. A marked drop in gas prices in 2006 from 2005 together with the modest 2006 production history of the two Swan Creek gas wells drilled in 2004 combined to eliminate the Company’s intent to drill additional gas wells in Swan Creek (described in p. 5). As a result of these economic realities the Company has removed all Swan Creek gas in the PUD category in 2006, and almost all in the PDNP categories (only 425 MCF remains in PDNP). This resulted in a downward reserve revision of 1300 Mcf and the removal of all the wells in the PUD category resulted in a downward revision on Swan Creek gas of 799 Mcf. An additional change of 1219 Mcf occurred in the PDNP category resulting from the removal of all but three future behind-pipe completions for shallow gas in Swan Creek. As a result of the removal or near removal of the wells in the PUD and the wells in the PDNP categories, the Company’s year-end 2006 reserve report and future reserve reports for Swan Creek gas reserves will accordingly reflect almost exclusively the value of proved producing properties. Those reports contained zero volumes and values for PUD’s and only 425 MCF for PDNP for Swan Creek gas reserves. Throughout the time of the Company’s involvement in Swan Creek in Tennessee the gas reserve values subsequent to initial production from the field begun in 2001 have been in constant downward revision. The extent and production capability and future value of Swan Creek now rest almost exclusively with current production (PDP). When compared to other investment options for the Company such as drilling for oil in Kansas at times of record oil prices, the Company has determined to perform no additional drilling in the foreseeable future in Swan Creek, which is the principal reason for the prior adjustments to the PDNP and PUD categories resulting in the downward revisions to the Company’s gas reserves during the last three years.

***

Tengasco, Inc. acknowledges that it is responsible for the adequacy and accuracy of the disclosure in the filing, that SEC staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and it may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We will await further comment from you with regard to each these matters before preparing and filing any amended pages of the Form 10-K or any amendment of the Form 10-Q as may be indicated in response to items 1-6 above to enhance the overall disclosure currently provided therein. We emphasize that no restatement of the financials is required by any of the comments made in your October 2 letter and consequently no restatement of any financial statement is necessary to meet the comments you have made. The Company continues to believe that the disclosure contained in the filings is sufficient to provide all information required to provide investors with the opportunity to make informed investment decisions.

Very truly yours,

Tengasco, Inc.

BY: s/Jeffrey R. Bailey

JEFFREY R. BAILEY, Chief Executive Officer