Tengasco, Inc.
10215 Technology Drive, Suite 301
Knoxville, TN 37932-4307
865.675.1554
865.675.1621 (facsimile)
February 29, 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 three numbered items in your letter dated February 12, 2008. The February 12 Letter refers to certain “PRIOR COMMENTS” contained in a letter dated January 15, 2008 and our written responses. This letter refers both to your numbered comments as of February 12, and the prior comment to which your February 12 comments are directed.
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:
1. | 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 one in which you propose to include a table that provides a breakdown of the standardized measure of discounted future net cash flows associated with various categories of proved reserves, both as to oil and as to gas, for each of the past three years. However, you have not proposed any action pertaining to the PV-l 0 non-GAAP measures amounting to $ 26,469,192 and $20,962,018, disclosed under this heading. We previously advised that these should be reconciled to GAAP based measures in accordance with the provisions in Item 10(e) of Regulation S-K, and that you should 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. Alternatively, if you are planning to replace that narrative with your tabulation, we would not object. However, there are several difficulties with the table that require your attention. Please revise to address the following points.
· | Replace the title "Reserve Value Analysis" with language clarifying that you are presenting a disaggregation of the standardized measure of discounted future net cash flows associated with proved reserves, rather than a separate valuation. |
· | Revise each caption or insert language before the group of line items to clarify that you are presenting the standardized measure of discounted future net cash flows associated with proved reserves, rather than reserve quantities. |
· | Reorder the columnar data to show fiscal years 2006, 2005 and 2004, in this chronological format, from left to right, consistent with how you present other numeric data in your filing, to comply with SAB Topic 11:E. |
OUR RESPONSE: We believe that all of the substance of your comment is resolved by (1) insertion of the following “TEXT” which will replace the first five existing paragraphs under the heading “Reserve Analyses” on page 23 of the 10-K; and (2) the insertion of the following “TABLE” which will replace the final paragraph on page F-32 beginning with “Of the Company’s total proved reserves…”:
TEXT
Reserve Analyses
The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2006, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following table. These estimates were prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Houston, Texas, and are part of their reserve reports on the Company’s oil and gas properties. Laroche’s estimates were based on a review of geologic, economic, ownership and engineering data that they were provided by the Company. In estimating the reserve quantities that are economically recoverable, end-of-period natural gas and oil prices, held constant, were used. In accordance with SEC regulations, no price or cost escalation or reduction was considered.
|
| Total Proved Reserves as of December 31, 2006 | ||||||||||
|
| Producing |
| Non-producing |
| Undeveloped |
| Total | ||||
Natural gas (MMcf) |
|
| 1,265 |
|
| 42.56 |
|
| 0 |
| 1,307 | |
Oil (Bbls) |
|
| 1,358,532 |
|
| 37,322 | 316,152 | 1,712,006 | ||||
Total proved reserves (BOE) |
|
| 1,569,365 |
| 44,415 | 316,512 | 1,930,292 | |||||
Standardized measure of discounted future net cash flow |
| $20,962,018 |
| $ | 1,572,837 |
| $ | 3,934,337 |
| $26,469,192 |
SEC regulations require that the natural gas and oil prices used in Laroche’s reserve reports are the period-end prices for natural gas and oil at December 31, 2006. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve reports but are adjusted by lease for energy content, quality, transportation, compression and gathering fees, and regional price differentials. The weighted average natural gas and oil prices after basis adjustments used in our reserve valuation as of December 31, 2006 were $56.59 per barrel and $8.33 per Mcf.
The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2006. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices. The 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.
An increase in oil reserves from 2005 to 2006 is reflective of the Company’s increased drilling activities in Kansas in 2006 and future drilling plans for 2007. The decrease in gas reserves from 2005 is due primarily to the Company’s determination not to drill any new wells in its Swan Creek Field and the substantial drop in the price used to calculate the gas reserves from $11.54 per Mcf in 2005 to $8.33 per Mcf in 2006. For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2006, 2005 and 2004, and the changes in quantities and standardized measure of such reserves for each of the three years then ended, see Note 21 to our consolidated financial statements.
TABLE:
BREAKOUT ANALYSIS OF ELEMENTS OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ASSOCIATED WITH PROVED RESERVES 2004-2006
| Year Ended 12/31/06 | Year Ended 12/31/05 | Year Ended 12/31/04 | ||||||
Standardized Measure of Future Net Cash Flows Associated with Total Proved Reserves, and with each of the following described categories of proved reserves ($000) with indicated percentage the cash flow of each category bears to cash flow of total proved reserves : | Oil | Gas | Total | Oil | Gas | Total | Oil | Gas | Total |
Total proved reserves ($000) | $23,606 | $2,863 | $26,469 | $23,530 | $13,649 | $37,179 | $12,073 | $14,658 | $26,731 |
Proved developed producing reserves (PDP) ($000) | $18,922 | $2,783 | $21,705 | $18,721 | $8,048 | $26,769 | $8,630 | $9,814 | $18,444 |
% of PDP to total proved reserves | 71% | 11% | 82% | 50% | 22% | 72% | 32% | 37% | 69% |
Proved developed non-producing reserves (PDNP) ($000) | $449 | $80 | $529 | $1,602 | $3,603 | $5,205 | $1,046 | $3,498 | $4,544 |
% of PDNP to total proved reserves | 2% | 0% | 2% | 4% | 10% | 14% | 4% | 13% | 17% |
Proved undeveloped reserves (PUD) ($000) | $4,235 | $0 | $4,235 | $3,207 | $1,998 | $5,205 | $2,397 | $1,346 | $3,743 |
% of PUD reserves to total proved reserves | 16% | 0% | 16% | 9% | 5% | 14% | 9% | 5% | 14% |
2. | Your Comment No. 2. Financial Statements; Note 1- Summary of Significant Accounting Policies, page F-9 Inventory, page F-10 |
. We understand from your response to prior comment two that you do not regard the estimated differences between your accounting for inventory at fair value and the accounting that would have arisen using historical cost to be material. You also explain that until 2006 you had commingled costs of oil and gas, because you had not created an accounting system for allocating costs to these separate products. We do not see this as a viable argument for not using historical cost as the accounting basis for inventory, given the guidance in ARB 43, Chapter 4, Statement 9. We believe that you will need to correct your accounting policy to utilize one that is generally accepted. Please make the necessary arrangements and follow the guidance in SFAS 154.
OUR RESPONSE:
As we previously noted, the estimated differences for previous periods was not material. With the recent sustained levels of higher commodity prices, we observed that the differences may approach materiality, so commencing with the third quarter of 2007 the Company has adopted the policy for all future periods to account for inventory at historical cost.
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 we previously indicated, 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.
3. | Form 10-Q for the Fiscal Quarter Ended September 30, 2007 |
Financial Statements Note 5- Related Party Transactions, page 10
We have read your response to prior comment three, regarding your September 17, 2007 agreement with Hoactzin Partners, LP (Hoactzin), under which you are responsible for drilling ten oil wells on your properties in Kansas. We understand that you have retained an economic interest equivalent to a 25% working interest in the wells until Hoactzin has recovered 1.35 times its "purchase price," after which your economic interest will increase to an effective 85% working interest. We also understand that you granted Hoactzin a 75% interest in your methane extraction project until this "payout point" is achieved, after which the interest drops to 7 1/2%; and that earnings from the oil wells plus earnings from the methane extraction project count towards this objective.
Given these provisions, along with those allowing Hoactzin to exchange its interests in the methane extraction project to convertible preferred shares, having conversion provisions based on the then market value of your common shares, and aggregate values based on an un-recovered portion of the "purchase price" at the end of 2009, and each of the four subsequent years, the arrangement seems to be substantively a borrowing.
Under Rule 4-10(c)(6) of Regulation S-X, you are directed to the guidance in SFAS 19 for mineral property conveyances and related transactions that are not specifically covered within the full cost rules. The guidance in paragraph 43(b) of SFAS 19 appears to have strong correlation with the arrangement you describe.
This would require that you establish a liability for the proceeds, rather than record the initial credit against your property account. This liability would later be reduced as Hoactzin recovers the "purchase price," and you would record interest expense for the increment between recovery and the "payout point." Further, if Hoactzin retains an effective 15% working interest in the oil wells after the payout point is achieved under all scenarios, a portion of the proceeds may need to be attributed to this sale, with a debit to deferred financing costs and a credit to the property account.
If you have additional information that you believe would yield an alternate view, please submit it with your reply. Otherwise, provide the accounting and disclosure revisions necessary to comply with this guidance.
In conjunction with your reply, tell us whether you intend to fully consolidate the drilling program and methane extraction project, before and after the payout point is achieved, or if you intend to use proportionate or equity method accounting at any point; and explain your rationale. Under the borrowing characterization, it appears you would need to address the consolidation question based on your retained interests of 85% in the oil wells and 92½% interest in the methane extraction project.
Please also clarify whether Hoactzin retains the 7 1/2% interest in the methane extraction project under the exchange for convertible preferred stock scenario.
OUR RESPONSE:
The substance of your most recent comment deals mainly with our intended accounting treatment of the referenced September 17, 2007 agreements. Earlier related comment requested additional disclosure language.
There follows a description of intended accounting treatment, together with the all proposed disclosure language SET OUT IN FULL for your ease in reference. We have added language in this disclosures to clarify that 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. This is the language we propose to add 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 below at “***”.
The revenues received by the Company under the September 17, 2007 agreements will be reported as a separate line item on the Company’s income statement. Although these revenues are referred to as management fees, as defined in the agreements they are 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. It is important to note that although Hoactzin may under certain circumstances exchange its interests for preferred stock at a value equal to its drilling program purchase price of $3.85 million, at no time under these agreements does Hoactzin have any right to receive preferred stock for the additional figure of about $1.35 million which is the difference between $3.85 million (Hoactzin’s purchase price) and $5.2 million (the point at which Hoactzin’s potential revenues if received would cause the parties’ interests to “flip” under the agreements.) Said another way, the figure of $5.2 million is simply a description of a point in time that might occur in the future revenue collection by Hoactzin and if it does, then Hoactzin’s interests are reduced and the Company’s are increased.
Tengasco proposes to employ normal joint-venture accounting through direct inclusion of its proportional share of the expenses, revenues, and assets to its agreement with Hoactzin. Under its analysis, the Company has conveyed an equity interest in particular oil and gas properties to Hoactzin. In the event there is a deficiency in future earnings from these properties, the remedy will be the issuance of equity. The instruments to be issued cannot be net settled, nor are other provisions apparent that would allow Hoactzin, in the event of shortfall, to settle other than in shares.
We believe that the facts and circumstances differentiate Tengasco’s agreement with Hoactzin from that addressed in SFAS 19, paragraph 43(b).
The citation to SFAS 19 reads:
“43. Certain transactions, sometimes referred to as conveyances, are in substance borrowings repayable in cash or its equivalent and shall be accounted for as borrowings. The following are examples of such transactions:
· | Funds advanced to an operator that are repayable in cash out of the proceeds from a specified share of future production of a producing property, until the amount advanced plus interest at a specified or determinable rate is paid in full, shall be accounted for as a borrowing. The advance is a payable for the recipient of the cash and a receivable for the party making the advance . . .” |
SFAS 19 at 43(b) can be viewed as a restatement of the rule that substance is to be given accounting recognition over mere form. However, as hypothesized in 43(b), the substance of the agreement in paragraph 43(b) of SFAS 19 differs from that of the Tengasco/Hoactzin agreement as to whether the transaction conveys an ownership interest (equity) or creates a liability.
The definition of a Liability from FASB Concept Statement No. 6, “Elements of Financial Statements”
“ . . . liabilities are claims to the entity's assets by other entities and, once incurred, involve nondiscretionary future sacrifices of assets that must be satisfied on demand, at a specified or determinable date, or on occurrence of a specified event.” [para. 54]
Claims against the entity’s assets
Addressed under the 43(b) hypothetical
The claim under 43(b) is against the entity’s existing assets – the presence of the interest component “payable at a specified or determinable rate” makes this clear. That the repayments are specified to be “out of future production” is the element of the agreement that we believe paragraph 43(b) of SFAS 19 is attempting to address – the temptation to give recognition to form over the substance of the agreement (otherwise, the example is so basic that its inclusion defies explanation).
Addressed under the Tengasco/Hoactzin Drilling agreement
The monetary claim in the Tengasco/Hoactzin Drilling agreement is against future earnings. The claim for what the SEC has analogized as ‘interest’ does not arise unless future earnings materialize. No monetary claim arises absent future earnings. This is an important distinction because liabilities represent claims against existing assets whose payment is “nondiscretionary.” Matching the liability against the asset not in existence is a violation of the overarching principles.
The fundamental distinction between the two scenarios is that, under 43(b) a claim arises against the Company’s assets, but in Hoactzin, the claim is against profits to be realized, or failing that, against equity.
FASB Concept Statement No. 6, “Elements of Financial Statements” addresses the concept of Equity:
From para. 55: “Although the line between equity and liabilities is clear in concept, it may be obscured in practice. Applying the definitions to particular situations may involve practical problems because several kinds of securities issued by business enterprises seem to have characteristics of both liabilities and equity in varying degrees”
So, the FASB Concept Statement No. 6, “Elements of Financial Statements” does not attempt a “definition” of equity, as such, but rather an enumeration of its characteristics. Principal among them in paragraph 54 and following are:
1. “In contrast, equity is a residual interest—what remains after liabilities are deducted from assets—and depends significantly on the profitability of a business enterprise
and
2. “A business enterprise may distribute assets resulting from income to its owners, but distributions to owners are discretionary, depending on the volition of owners or their representatives after considering the needs of the enterprise and restrictions imposed by law, regulation, or agreement
and
3. “An enterprise's liabilities and equity are mutually exclusive claims to or interests in the enterprise's assets by entities other than the enterprise, and liabilities take precedence over ownership interests.
and, from paragraph 62:
4.“. . . that is, some classes of owners may bear relatively more of the risks of an enterprise's unprofitability or may benefit relatively more from its profitability (or both) than other classes of owners. However, all classes depend at least to some extent on enterprise profitability for distributions of enterprise assets, and no class of equity carries an unconditional right to receive future transfers of assets from the enterprise except in liquidation, and then only after liabilities have been satisfied.”
Under this guidance, the Company has concluded that what was conveyed in Hoactzin was an equity interest in the oil and gas properties:
1. What is to be distributed is a “residual interest” – a proportion of the working interest, which is calculated net of expenses attributable to the entity. Earnings, dependent upon the profitability of the venture.
2. The distributions to the owners are volitional and – because subject to upfront “restrictions imposed by agreement” amongst the owners – are not rendered of a different nature than equity.
3. | A characteristic of equity is that “liabilities take precedence over ownership interests.” The position of Tengasco as the operator in regards to an oil well or a group of wells is not the equivalent of establishing a precedence to the earnings of those with whom the Company is splitting earnings. |
4. Finally, that “no class of equity carries an unconditional right to receive future transfers of assets from the enterprise” is not a principle violated here, as future distributions are conditioned on profitability. Other conditions present here a disproportionate distribution of earnings do not negate the presence of equity.
The Company did not consider that the inclusion of the equity ‘kicker’ in the deal could possibly give what was a straight-up equity deal the earmarks of a debt transaction.
The Company views the convertible preferred component as an option with a performance condition. Accordingly, no value has been accorded these options prior to “performance” – here the failure of the Company to comply with the terms of the conveyance. If preferred shares are issued, the Company proposes to debit its investment in oil and gas and credit APIC.
At any rate, the Company’s analysis, made prior to the conveyance, attached little fair value to the preferred stock option. Accordingly, this provision of the agreement was ceded without significant negotiation.
Seen as a ‘guarantee’ the Company believed that exercise of the preferred option in any amount material to the financial statements was, at best, a remote contingency.. Events subsequent to contract date have borne out this judgment. These analyses give no weight to additional cash flows that might be attributable to the manufactured methane installation in Tennessee.
Given the further considerations below as to the adequacy of its disclosure, the Company elected to include no adjustment to its equity accounts for the fair value of the option given.
Finally, given the application of joint venture accounting, the Company believes that no consolidation of the Hoactzin agreement is appropriate.
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:
***[begin insert:]
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 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 (ultimately $3.85 million for the ten drilled wells) paid for the drilling program, or approximately $5.2 million. 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 was 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 (March ___, 2008) all ten of the wells have been drilled. Of the ten drilled wells, 9 have been completed as producers and are 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 program wells that have been drilled, or drilled and completed.
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. 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 Hoactzin’s invested funds 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 drilling program), then Hoactzin would have an option to exchange 20% of its methane project interest in 2010 and each year thereafter for preferred stock with liquidation value of 100% of its drilling program investment (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 as of the date of this amended report.
However, the Company anticipates that with the demonstrated successful results 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 nine 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 approximately 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.
***[end]
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 1-3 above, and previous comments to which our responses are presumed to be satisfactory, 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 letters 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