This letter follows up our telephone conversation with you and others in your offices concerning the accounting treatment of the September 17, 2007 transaction between Tengasco, Inc. and Hoactzin Partners, LP consisting of a ten well drilling program, net profits interest in methane project, and contingent exchange agreement of methane net profits interest for preferred stock. For reference in this letter, this will be referred to as the “Hoactzin Agreement”.

We understand that Staff concluded the most recent phone call by stating a desire to review a statement of our “overarching view of materiality” of the impact of deferred conveyance accounting on the Hoactzin Agreement. The staff also requested that we provide further discussion and analysis as to (1) the applicability of EITF 88-18 to the transaction (2) the sufficiency of related party disclosure with respect to the requirements of FAS 57 and FAS 69 ¶30(a), and (3) depletion calculations assuming company ownership of volumes allocable to its net profits interests.

As a matter of housekeeping, in our prior telephone conversation with the staff, we had indicated that we believed the “deferred revenue” model best represents proper accounting, given the nature of the agreement with Hoactzin. Use of the phrase “deferred revenue” represents a confusing choice of terminology on our part. Our concept did involve deferral of the conveyance but incorporated the use of a method of writing off the deferred credit that could more closely be termed the “deposit method.” The term “deposit method” will be used in this letter to indicate the method of writing off the deferred credit we had previously illustrated in

the spreadsheet analysis supplied to the Staff in our last written response. The term “deferred revenue method” will be used to refer to revenue recognition under EITF 88-18. The term “joint venture method” will be used to refer to the original presentation made by the Company in the 10-K for the year ending December 31, 2007.

It is the Company’s position that there is no material difference in the financial presentation between the deposit method and the original joint venture presentation made by the Company in the 10-K for the year ending December 31, 2007 that we continue to believe to be the appropriate accounting for the issues raised. However, we would not object to the use of “deposit method” accounting. We also are of the position that the use of the “deferred revenues” method results in incorrect accounting, i.e. early overstated income and early overstated net assets if applied to the Hoactzin Agreement.

As an initial matter we discuss the materiality of the Hoactzin Agreement to Company operations. Quantitatively we considered the following concerning the overall impact the transaction bore to the rest of the Company's operations as of December 31, 2007.

A quantitative analysis as to the materiality of the effects of the prior (joint venture) accounting compared with a deferred conveyance (either deferred revenue or deposit method) accounting appears below. The analysis is made as of December 31, 2007.

Effects on Balance Sheet	JOINT VENTURE ACCOUNTING (AS INITIALLY REPORTED)		RECORDED AS DEFERRED CONVEYANCE (DEFERRED REVENUE METHOD & DEPOSIT METHOD)
		Amount		Amount
Total Assets		34,281,000		38,131,000
Total Liabilities		6,178,000		10,028,000
Equity		28,103,000		28,103,000

Long Term Assets		30,476,000		34,326,000
Long Term Liabilities		4,315,000		8,165,000

Current Assets		3,805,000		3,805,000
Current Liabilities		1,332,000		1,332,000

In the table below, we add to the discussion, what occurs in later years as well as the effects of a theoretical depletion calculation that would necessarily include revenues corresponding to the depletion taken.

	Depletion	104,361	-	-
	Net Income	$ 75,240	$ 46,815	$ 46,815
	Net Cash Flows	$ 46,815	$ 46,815	$ 46,815

Year 2 (thru 12/31/08)
	Revenue Recognition	$ 1,642,737	$ 428,197	$ 428,197
	Depletion	477,277	-	-
	Net Income	$ 1,165,460	$ 428,197	$ 428,197
	Net Cash Flows	$ 428,197	$ 428,197	$ 428,197

Year 3 (thru 12/31/09)
	Revenue Recognition	1,111,404	431,537	431,537
	Depletion	299,242	-	-
	Net Income	$ 812,162	$ 431,537	$ 431,537
	Net Cash Flows	$ 431,537	$ 431,537	$ 431,537

	Cumulative revenue	$ 2,933,742	$ 906,549	$ 906,549
	Cumulative depl.	$ 880,880	$ -	$ -
	Cumulative NI	$ 2,052,862	$ 906,549	$ 906,549

According to EITF 88-18, the issue before it was: “An enterprise receives cash from an investor and agrees to pay to the investor for a defined period a specified percentage or amount of the revenue or of a measure of income (for example, gross margin, operating income, or pretax income) of a particular product line, business segment, trademark, patent, or contractual right. It is assumed that immediate income recognition is not appropriate due to the facts and circumstances. The payment to the investor and the future revenue or income on which the payment is based may be denominated in a foreign currency.”

In the above particulars, we believe the EITF has been addressed in ¶220 of FAS 19 and rejected there for debt treatment – debt treatment arising there under a set of facts that do not resemble Hoactzin. Neither do any of the six conditions triggering debt accounting which EITF 88-18 enumerates in the second paragraph fit the current situation, although we consider criteria two and six to be close, turning on matters of definition. FAS 19 does provide for a type of deferral of revenue when a specific quantity of minerals are sold in place. Again, the situation does not closely resemble Hoactzin. As the Staff had remarked earlier, a precise fit with promulgated GAAP and example illustrations may not exist.

In our proposed accounting, we have adopted, in our “deferred conveyance accounting,” something resembling the “deposit method” – in recognition of that method’s closer fit with the economic realities of Hoactzin. Under the deposit method, upon expiration of the legally enforceable liability (the “guarantee,” however defined), no accounting liability would remain on the Company books. No revenue is attributed to the decrement of the liability, instead the asset is ratably written off periodically to reflect the sale, ultimately in its entirety upon the settlement of the guaranteed payment stream – the “guaranteed” payment stream, once satisfied, no longer acting as an impediment to recognition of the sale. Income recognition is not a concern as in the EITF, when provisions act in the usual situation to defer revenue recognition, as income will be recognized only after recognition of the sale under FAS 19 and in accordance with usages and customs common to the industry. Thus, when the impediment is removed, higher level GAAP comes into force.

We believe that we have previously satisfied the related party disclosure requirements of FAS 57 and FAS 69 ¶30(a). If any deficiencies in the notes to the financial statements exist we will supplement, with information previously made available to the public as part of our Forms 10K and 10Q, that disclosure going forward. For your convenience in reference, we attach the disclosure already made in our 2007 10-K and the 10-Q’s for the first, second, and third quarters of 2008.

We have recalculated depletion for Tengasco based on retention of a volumetric interest in the Hoactzin properties. Such calculations become relevant under ¶220 of FAS 19, which adds explanatory language for the situation described in ¶43(b). According to ¶220, if the Company

records the effect of the “guarantee” (legal sale) as debt under given specific circumstances, the ‘reserves and production involved are reported by the recipient’ [of the funds (Tengasco)].

¶220 specifically rejects a deferred revenue treatment under the circumstances specified, but elsewhere in FAS 19, at ¶47(a), we find a reference to a situation akin to deferred revenue accounting. There, the situation calls for the guaranteed delivery of quantities in place rather than a guaranteed dollar amount and so is distinguishable from the Hoactzin case. Perhaps because of the difference between Hoactzin and ¶47(a) or perhaps because of a need to match expense with revenue, the Staff requested that Tengasco investigate the effects of recording depletion in a deferred revenue situation, as well.

The first aspect of recognizing depletion is that, unlike the deposit method, resulting revenues must be recognized too. Since the Company, in depleting the assets, would be rejecting the legal form of a sale, the relevant revenue recognition policy for the attendant revenues from which the proceeds arise which will be used to pay down the debt becomes a central issue. The Staff asked the Company to consider EITF 88-18, which distinguishes between situations calling for debt accounting or deferred revenue accounting.

We calculated the effects of applying both deposit and deferred revenue methods and believe that, in the absence of a close factual fit, the use of the deposit method might solve the matching problem attendant with the problems of depletion and revenue recognition accounting. Under deposit accounting, which is generally appropriate in transactions involving real estate when the liability is anticipated to turn around within a relatively short time-frame, a mirror entry for the amount of proceeds paid to Hoactzin would be debited against the liability recorded and credited against the grossed-up asset, with no impact upon the income statement. By bringing the depletion of resources legally conveyed into the income statement, the Company would be presented with a significant matching problem which is solved, the Company believes, inappropriately, by either of the two revenue recognition methods prescribed in EITF 88-18.

The Company’s calculations involved modeling the transaction and the adoption of various simplifying assumptions. Different assumptions might lead to different dollar amounts, but the general contours of revenue/expense recognition are apparent from the model. The deferral method under EITF 88-18, whereby a pro-rata component of funds previously received is considered repaid based on total expected life-time payments under the agreement, would result in Tengasco recognizing an increase in revenues, an increase in depletion and an increase in Net Income from transactions with Hoactzin. The model shows an increase of income, net of depletion, on the recognition of revenue using the deferred revenue method of EITF 88-18. The net income will derive from the front loading of repayments to Hoactzin (and the recognition of income which repayments drive) relative to the depletion of full-cost reserves.

We have not projected beyond 2009 because depletion calculations under the full-cost method require knowledge of company-wide future costs and reserves that are beyond any reliable prognostication. However (with no revisions for changed reserves), about 80% of amounts projected to be repaid to Hoactzin over the life of the agreement will have been repaid by 2009 but only about 15% of depletion of the three million dollar base will have been charged against the Company’s income.

The immaterial variance in income for 2007 resulted from grossing up depletable assets by $3,000,000 so that minimal Hoactzin production in 2007 skews the depletion calculation more than might be expected. The reason appears to be that Hoactzin production is relatively expensive compared to Tengasco's base production – approximately $3.0 million (the assumed allocation of the proceeds of $3.85 million) plus about $2.8 million in development costs for an estimated 209,434 bbl of cumulative production. (These barrels include production from wells that were not completed until 2008.) These numbers would intuitively calculate on a stand-alone basis to depletion of about $28/bbl.

The resulting calculations yield an immaterial increase to Net Income for 2007. However,

in the second year, and using the January 1, 2008 petroleum engineers’ report without adjusting for any experience-driven revisions of estimated volume and revenue (which will only affect pro-rata calculations for Hoactzin minimally due to the achievement of the “flip point” whereby its interest reduces to 15%), Tengasco would recognize $1,642,737 in revenue and match only $477,277 in depletion. letion (the depletion calculation being affected by the acquisition of Black Diamond and the expansion of depletable reserves as well as by more extensive production from the Hoactzin property).

Because the shape of an oil well decline curve tends to bunch anticipated income and depletion to early production, and because the flip-point emphasizes this process with respect to income recognition only, expected repayments (and resulting income recognition) are disproportional in the early years even to depletion, resulting in the acceleration of income recognition under the deferred revenue approach of EITF 88-18. The ‘contour’ of our models resulting from the flip-point feature of the Hoactzin agreements indicates that acceleration of revenues will occur in the early years up to reaching the flip point, regardless of recognition using EITF 88-18’s deferred revenue method or its interest method.

Based on all of the above, we have reached two conclusions about the three possible theories (i.e. (1) the Company’s original presentation using joint venture accounting; (2) the “deposit” method, which results in the same income; and (3) the “deferred revenues” method.) First, there is no material difference between the Company’s original presentation and the “deposit” method – the difference being entirely balance sheet and (primarily) long-term. Second, the “deferred revenues” method results in materially overstated revenues and net income for purely theoretical reasons not compatible with the parties’ intent in the actual transaction and in circumstances differing from example literature. Consequently we believe an appropriate resolution of this matter is to maintain the Company’s presentation in its original filings, although we would not object to the use of “deposit method” accounting.

We believe this fully addresses and properly resolves all matters raised in the recent telephone conversation and provides a basis for concluding this matter with no further action being required of the Company. Should you have any further requirement please let us know and the basis for the position taken so that we may properly respond so that these matters may be concluded.

Except as set forth hereafter, there have been no material transactions, series of similar transactions or currently proposed transactions during 2006 and 2007, to which the Company or any of its subsidiaries was or is to be a party, in which the amount involved exceeds the lesser of $120,000 or one percent of the average of the Company’s total assets at year-end for its last two completed fiscal years in which any director or executive officer or any security holder who is known to the Company to own of record or beneficially more than 5% of the Company's common stock, or any member of the immediate family of any of the foregoing persons, had a material interest.

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

The Company has drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 106 barrels per day in total. Hoactzin paid a total of $3,850,000 for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.6 million for the ten wells by more than $1 million.

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

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 Industrial. The Agreement was thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) and provides that MMC will purchase the entire naturally produced gas stream presently being collected and flared at the municipal solid waste landfill in Carter Valley serving the metropolitan area of Kingsport, Tennessee that is owned and operated by BFI in Church Hill, Tennessee. BFI’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). Contingent upon obtaining suitable financing, the Company plans to acquire and install a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream. Methane is the principal component of natural gas and makes up about half of the purchased gas stream by volume. The Company plans to

construct a small diameter pipeline to deliver the extracted methane gas to the Company’s existing pipeline for delivery to Eastman (the “Methane Project”).

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

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

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

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. When the Methane Project comes online, the revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the Ten Well Program. When the Payout Point is reached from either the revenues from the wells drilled in the Program or the Methane Project or a combination thereof, Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5% net profits interest. The Company believes that the application of revenues from the Methane Project to reach the Payout Point could accelerate reaching the Payout Point. As stated above, the price paid by Hoactzin for its interest in the Program exceeded the Company’s anticipated and actual costs of drilling the ten wells in the Program. Those excess funds provided by Hoactzin were used to pay for approximately $1,000,000 of equipment required for the Methane Project, or about 25% of the Project’s capital costs. The availability of the funds provided by Hoactzin eliminated

the need for the Company to borrow those funds, to have to pay interest to any lending institution making such loans or to dedicate Company revenues or revenues from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the Company as a favorable element to the Company of the overall transaction.

The Company also announced that on September 17, 2007 it entered into an additional agreement with Hoactzin providing that if the Ten Well 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 (the “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 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 American Stock Exchange. 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. 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 impossible in view of the success of the Ten Well 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. 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.

However, the Company anticipates that with the demonstrated successful results of the Ten Well Program that the payout of 25% of the Purchase 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 the Methane Project to come online in 2008, that the balance of the unrecovered Purchase Price by Hoactzin will also be reduced by at least 20% each year thereafter. Based only on current production from the nine producing wells in the Ten Well Program (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 approximately 66% of the Purchase Price, far in excess of the 25% required in order to obviate any occasion to exchange its interest in the Methane Project 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.

Hoactzin producing drilling program wells	9
Company total producing wells	196
% of Hoactzin’s wells to total TGC wells	4.6%
Total Reserves- BOE- gross	3,130,941
Hoactzin’s reserves -gross	101,068
Hoactzin’s reserves- net of Company interest	58,526
Hoactzin as percentage of total reserves-net	1.9%

Isolated Effects on Income Statement, Cash Flows

Deferred Revenues Method

Joint Venture

Deposit Method

Year 1 (thru 12/31/07)

Revenue Recognition