Riley Exploration Permian, Inc. - Quarter Report: 2009 June (Form 10-Q)

U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

Commission File No. 1-15555

Tengasco, Inc.

(Exact name of issuer as specified in its charter)

10215 Technology Drive, Suite 301, Knoxville, TN 37932

(Address of principal executive offices)

(865-675-1554)

(Issuer’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes____ No X  

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 59,360,661 common shares at August 1, 2009

TABLE OF CONTENTS

TENGASCO, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

See accompanying notes to condensed consolidated financial statements

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TENGASCO, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

See accompanying notes to condensed consolidated financial statements

4

TENGASCO, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to condensed consolidated financial statements

5

TENGASCO, INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

See accompanying notes to condensed consolidated financial statements

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TENGASCO, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to condensed consolidated financial statements

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Notes to Consolidated Financial Statements

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the six months ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ended December 31, 2009. For further information, refer to the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry-forwards and a ceiling test write-down. Management evaluates the likelihood of realization for such assets at year-end providing a valuation allowance for any such amounts not likely to be recovered in future periods. The Company currently has a net operating loss carry-forward of $15.6 million.

As of December 31, 2008, the Company also had a deferred tax asset totaling $3.9 million related to a ceiling test write-down of $11.6 million. This deferred tax asset arose from differences between the financial statement carrying value of the Company’s oil and gas properties and their respective income tax bases (temporary differences) after taking into consideration the reduced depletion expense from the ceiling test write down. To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of this deferred tax asset will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Management has determined that it is more likely than not that all of this deferred tax asset will be realized. The $3.9 million deferred tax asset related to the ceiling test write-down is in addition to the deferred tax assets resulting from the Company’s net operating loss carry-forwards.The total deferred tax asset at June 30, 2009 is $9,100,880.

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Notes to Consolidated Financial Statements

In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,357,804 and 59,189,990 weighted average shares outstanding for the quarters ended June 30, 2009, and June 30, 2008, respectively and 59,354,252 and 59,173,178 for the six months ended June 30, 2009 and June 30, 2008 respectively. Diluted earnings per common share are computed by dividing income available to common shareholders by the weighted-average number of shares of common stock outstanding during the period, increased to include the number of additional shares of common stock that would have been outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options is reflected in diluted earnings per share for June 30, 2008. Dilutive shares outstanding at June 30, 2009 were 2,234,000, related to outstanding options. These shares were not included in the Earnings Per Share for the first six months of 2009 as they were anti-dilutive.

In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K. The new requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations. The final rules are effective for fiscal years ending on or after December 31, 2009. The Company has adopted the rule effective January 1, 2009.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“SFAS No. 157”), which applies under most other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements. SFAS No. 157 had originally been effective for financial statements issued for fiscal years beginning after November 15, 2007, however the FASB has agreed on a one year deferral for all non-financial assets and liabilities. The Company adopted SFAS 157 effective January 1, 2008. Adoption of this statement did not have a material impact on the Company’s financial condition, results of operations, and cash flows.

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Notes to Consolidated Financial Statements

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Ten Well Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management, Inc. the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. Carlos P. Salas, a director of the Company, has an interest in Hoactzin but is not a controlling peron of Hoactzin. Under the terms of the Ten Well Program, Hoactzin was to pay the Company $400,000 for each well in the Ten Well Program completed as a producing well and $250,000 for each well drilled that was non-productive. The terms of the Ten Well Program also provide that Hoactzin will receive all the working interest in the ten wells in the Program, but will pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but, as defined, is in the nature of a net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of working interest revenues when and if net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Ten Well Program.

In March 2008, the Company drilled and completed the tenth and final well in the Ten Well Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 90 barrels per day in total. Hoactzin paid a total of $3,850,000 (the “Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.8 million for the ten wells by more than $1 million.

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

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

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Notes to Consolidated Financial Statements

Hill, Tennessee (the "Methane Project"). Revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the Ten Well Program. When the Payout Point is reached from either the revenues from the wells drilled in the Ten Well Program or the Methane Project or a combination thereof,

Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5% net profits interest.

On September 17, 2007, the Company also entered into an additional agreement with Hoactzin providing that if the Program and the Methane Project interest in combination failed to return net revenues to Hoactzin equal to 25% of the Purchase Price it paid for its interest in the Ten Well Program by December 31, 2009, then Hoactzin would have an option to exchange up to 20% of its net profits interest in the Methane Project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the Purchase Price less the net proceeds received at the time of any exchange. At the time the agreement was negotiated, the Company's forecast of the probable results of the projects indicated that there was little risk that the option to acquire preferred stock would ever arise, so the Company placed no significant value to the preferred stock option. By June 30, 2009 the amount of net revenues received by Hoactzin from the Ten WellProgram has reduced the Company’s obligation to Hoaztzin for the amount of the funds it had advanced for the Purchase Price from $3,850,000 to $1,669,681. 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 highly unlikely in view of the success of the Program), then Hoactzin would have an option to exchange 20% of its interest in the Methane Project in 2010 and each year thereafter for preferred stock with liquidation value of 100% of the Purchase Price (not 135%) convertible at the trailing average price before each year’s issuance of the preferred stock. The maximum number of common shares into which all such preferred stock could be converted cannot be calculated given the formulaic determination of conversion price based on future stock price.

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Notes to Consolidated Financial Statements

However, revenues from the Ten Well Program have resulted in 57% of the Purchase Price having already been reached. Accordingly, it is highly unlikely that any requirement to issue preferred stock will arise in 2010 or any succeeding years.

(6.) Deferred Conveyance/Prepaid Revenues

The Company has adopted a deferred conveyance/prepaid revenues presentation of the transactions between the Company and Hoactzin Partners, L.P. on September 17, 2007 to more clearly present the effects of the three-part transaction consisting of the Ten Well Program, the Methane Project and a contingent exchange option agreement. This deferred conveyance presentation for the year 2008 will be compared to adjusted year-end 2007 figures for the purposes of this comparison.

As part of the deferred conveyance presentation, the Company has allocated $853,000 of the $3.85 million Purchase Price paid by Hoactzin for its interest in the Ten Well Program to the Methane Project, based on a relative fair value calculation of the Methane Project’s portion of the projected payout stream of the combined two projects as seen at the inception of the agreement, utilizing then current prices and anticipated time periods when the Methane Project would come on stream. The Ten Well Program at inception was $2,997,000 and the prepaid revenues were $853,000.

The Company has established separate deferred conveyance and prepaid revenue accounts for the Ten Well Program and the Methane Project. Release of the deferred amounts to the Ten Well Program will be made as proceeds are actually distributed to Hoactzin. Release will be made on the respective proceeds only as to each project until either one or both satisfy the threshold amount that removes the contingent equity exchange option. All releases for periods through December 31, 2008 are to the Ten Well Program as the Methane Project was not scheduled to go online until late in 2008 and gas revenues would first be received in 2009. The prepaid revenues will be released using the units of production method when the Methane Project comes online in 2009.

The impact of the Hoactzin Agreement through December 31, 2008 is as follows. Of the $3,850,000 Purchase Price invested by Hoactzin in September 2007, a total of $120,058 was paid to Hoactzin by December 31, 2007 attributable to the production of 1,403 barrels of oil in 2007 attributable to Hoactzin’s interest. All proceeds paid to Hoactzin in 2008 were from Hoactzin’s interest in the Ten Well Program oil wells. The volume that is attributable to Hoactzin’s interest is 19,438 barrels for the yearly production through December 31, 2008 for a total of $1,779,777 in 2008.The reserve information for the parties’ respective Ten Well Program interests during calendar year 2008 are indicated in the table below. Reserve reports are obtained annually and estimates related to those reports are updated upon receipt of the report. These calculations were made using the 2008 year-end price of $34.04 per barrel, as required by SEC regulations. It should be noted that the table reflects only the reserve valuations based on the fact that in 2008 only the Program wells were contributing to reaching the point when the Company receives a larger portion of the production, sometimes referred to as the “flip point.” Hoactzin paid a total

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Notes to Consolidated Financial Statements

Purchase Price of $3,850,000 for its interest in the Ten Well Program resulting in the Payout Point or “flip point” being determined as $5,215,595. In fact, when the Methane Project contributes to the Payout Point being reached, this will accelerate that process. Thus, the Company’s reserves attributable to its interests will increase from those listed in this table because of the contribution made by Methane Project proceeds toward reaching the Payout Point when the Company’s interest in production increases.   This fact does not consider the additional but separate effect of price changes for both oil and for gas, which will also affect the annual determination of reserve values.

Reserve Information for Ten Well Program Interests

For Year Ended December 31, 2008

As of year-end 2008 the original invested amount of $3,850,000 has been reduced by 50% to $1,950,165. This amount is the total of the deferred conveyance of $1,097,165 and the prepaid revenue account of $853,000. Hoactzin’s first right to convert its invested amount of $3,850,000 into preferred stock is only exercisable to the extent Hoactzin’s investment has not been reduced by 25% by the end of 2009. For each year after 2010 in which Hoactzin’s then-unrecovered invested amount at the beginning of the year is not reduced 20% further by the end of that year, Hoactzin has a similar option. Consequently, Hoactzin is already precluded by these results from any possibility of exercising its contingent option under the exchange agreement to convert into preferred stock until the year ending December 31, 2011 at the earliest. All of the $1,899,835 paid from the program has been from the Ten Well Program and the deferred conveyance account has been reduced from $2,997,000 to $1,097,165.

As noted, in future periods, the Company anticipates that this Hoactzin investment will continue to be further reduced by sales of oil produced from the Ten Well Program, or methane produced from the Methane Project, or both. From inception of the project through December 31, 2009, the Company projects that the original $3.85 million Purchase Price will be reduced by 76% to $924,000. For the year ending December 31, 2010, the amount is projected to be reduced to $0. As a result, Hoactzin’s contingent option to exchange for preferred stock would fully terminate without any further annual reduction tests. These projections are based upon expected production levels from the oil wells in the Ten Well Program and an estimated 400 Mcf/day production from the Methane Project using $40 oil prices and a $5 per Mcf gas sales price net of operating expenses. The projection will vary with the actual oil and

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Notes to Consolidated Financial Statements

gas prices, production volumes, and expenses experienced in 2009 and 2010. Based on these projections the Company considers that it is a remote contingency that any right of Hoactzin to elect to exchange its Methane Project interest for Company preferred stock will ever arise. However, in the event of a conversion of Hoactzin’s Methane Project interest for Company preferred stock as set out in limited circumstances in the applicable agreement, and which the Company anticipates is highly unlikely, there would be a debit to the deferred conveyance liability and the prepaid revenue account for both the Ten Well Program and Methane Project because no contingent option would remain on such a conversion and the Company would simultaneously credit preferred stock in the converted amount. In the event of the termination of the option to convert into preferred stock because the $3.85 million has been repaid from the Ten Well Program or Methane Project or both, the applicable oil and gas properties will be deemed to have been fully conveyed to Hoactzin and the Ten Well Program account, will be credited and the liability will be removed, as at this time the price received for the program will be fixed and determinable. Under this circumstance, the prepaid revenue account would continue to be released under the units of production method.

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

The Company recorded $275,000 and $550,000 in depletion expense for the first three and six months of 2009 and 2008 respectively.

The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. The Company’s asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date. The Company’s calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 8%, an estimated useful life of wells ranging from 30-40 years and an estimated plugging and abandonment cost of $5,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.

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Notes to Consolidated Financial Statements

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

On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company. Under the facility as assigned to Sovereign, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $20 million or the Company’s borrowing base in effect from time to time. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment. 

On June 2, 2008, the Company entered into an amendment to its credit facility with Sovereign whereby the Company’s borrowing base was raised by Sovereign as a result of its review of the Company’s currently owned producing properties.  The borrowing base was raised to $11 million effective June 2, 2008.  The Company had previously utilized about $4.2 million of the facility, leaving approximately $6.8 million then available for use by the Company upon this borrowing base increase.  The Company used $5.35 million of the then available $6.8 million for the purchase of the Riffe Field properties in Kansas.  The total borrowing by the Company under the facility at year end 2008, and as of the date of this Report, is $9.9 million.

On February 5, 2009, the Company amended its credit facility with Sovereign to provide for a monthly reduction of the Bank’s commitment by $150,000 per month for the five month period of February through June 2009.  This commitment reduction is not a cash payment obligation of the Company but has the effect of reducing the Company’s available borrowing base in monthly increments of $150,000 so that by June 2009 the Company’s available borrowing base under the Sovereign facility was to be reduced by $750,000 from $11.0 million to $10.25 million. 

On July 9, 2009, the Company’s borrowing base was increased from $10.25 million to $11.0 million under the revolving senior credit facility between the Company and Sovereign. The Company’s borrowing base was increased on the completion of the regular semiannual borrowing base review by Sovereign. The $11.0 million borrowing base is again made subject to a monthly available-credit reduction (MCR) of $150,000 per month beginning August 5, 2009, so that by the time of the next regular borrowing base review in six months, the borrowing base will again be $10.25 million.

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Notes to Consolidated Financial Statements

On October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC (“BFI”), an affiliate of Allied Waste Industries (“Allied”). In 2008 Allied merged into Republic Services, Inc. (“Republic”). The Agreement was thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”), and provides that MMC will purchase all the naturally produced gas stream presently being collected and flared at the Carter Valley municipal solid waste landfill owned and operated by Republic in Church Hill, Tennessee serving the metropolitan area of Kingsport, Tennessee. Republic’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). The Company has installed a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream.  Methane is the principal component of natural gas and makes up about half of the purchased raw gas stream by volume. The Company has constructed a small diameter pipeline to deliver the extracted methane gas to the Company’s existing pipeline (the “Methane Project”).

The total cost for the Methane Project including pipeline construction, was approximately $4.5 million including costs for compression and interstage controls. The costs of the Methane Project were funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million; (b) cash flow from the Company’s operations; and (c) $825,000 of the funds the Company borrowed under its credit facility with Sovereign Bank. Methane gas produced by the project facilities was initially mixed in the Company’s pipeline and delivered and sold to Eastman under the terms of the Company’s existing natural gas purchase and sale agreement with Eastman. At current gas production rates and expected extraction efficiencies, the Company initially estimated it would deliver about 418 MCF 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. 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 Republic 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 Republic, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations

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Notes to Consolidated Financial Statements

of pipeline. Republic has paid the additional material costs for including the water line of approximately $700,000. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline began in January 2008 and was completed in December 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, required no additional permits for the gas pipeline construction.

At year-end 2008, MMC finalized steps necessary to declare the startup of commercial gas production at the Carter Valley landfill in Church Hill, Tennessee.  Initial volumes of methane were produced in late December 2008 and have occurred on an intermittent basis since that time as MMC implemented the startup process. During the first two months of 2009, Eastman Chemical was reviewing its current air quality permits with regard to MMC’s methane production and deliveries were suspended during that review. 

The Company declared startup of commercial operations on April 1, 2009.  To date of this report, MMC has produced approximately 20,065,000 cubic feet of methane gas that was extracted from the landfill gas. 

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

Effective as of July 1, 2008, the Company purchased from Black Diamond Oil, Inc. an expected 80 barrels per day of oil producing properties and related leases and equipment in Rooks County, Kansas for $5.35 million. The Company has acquired producing oil wells and saltwater disposal wells, equipment, and the underlying working interests in leases comprising what is known as the Riffe field that had been owned by

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Black Diamond for many years. The purchase price was paid primarily from borrowings under its credit facility with Sovereign and from cash on hand. Following the purchase, the Company had borrowed a total of $9.9 million under its credit facility.

ITEM 2.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL                     CONDITION AND RESULTS OF OPERATIONS

During the first six months of 2009, the Company sold 122,012 gross barrels of oil from its Kansas Properties comprised of 184 producing oil wells. Of the 122,012 gross barrels, 88,059 barrels were net to the Company after required payments to all of the Drilling Program participants and royalty interests. The Company’s sales for the first six months of 2009 of 88,059 net barrels of oil compares to 70,743 barrels sold to the Company’s interest in the first six months of 2008. Although the Company’s production for the first six months of 2009 increased by 24% from the first six months in 2008, the Company’s net revenues from the Kansas properties were $3,850,271 in the first six months of 2009 compared to $7,383,488 in 2008. This decrease was due to a drop in oil prices to an average of $44.13 per barrel in 2009 from an average of $104.37 per barrel in 2008. The Company’s sales from Tennessee for the first six months of 2009 included $102,236 from oil sales, $119,921 from Swan Creek gas sales, and $73,521 from Manufactured Methane sales.

Comparison of the Quarters Ended June 30, 2009 and 2008.

The Company recognized $2,354,629 in revenues during the second quarter of 2009 compared to $4,633,588 in the second quarter of 2008. The decrease in revenues was due to a sharp decrease in oil prices in 2009. Oil prices in the second quarter of 2009 averaged $52.52 per barrel compared to $117.37 per barrel in the second quarter of 2008. The Company realized a net loss attributable to common shareholders of $(80,593) or $(0.00) per share of common stock during the second quarter of 2009, compared to a net income in the second quarter of 2008 to common shareholders of $1,421,707 or

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$0.02 per share of common stock. The Company recorded non-cash income tax expense of $740,000 for the second quarter net income in 2008.

Production costs and taxes in the second quarter of 2009 decreased to $1,310,357 from $1,408,116 in the second quarter of 2008. The difference is due to the Company’s cost-cutting measures to control expenses due to the reduced prices for oil. These measures have also resulted in a decrease in volumes produced from the first quarter of 2009. The Company sold 66,435 gross barrels in the first quarter 2009 compared to 55,577 gross barrels in the second quarter 2009.

Depreciation, depletion, and amortization expense for the second quarter of 2009 was $482,955 compared to $473,646 in the second quarter of 2008. The depletion percentage has remained consistent with the total oil & gas properties.

Interest expense for the second quarter of 2009 increased to $155,159 from $72,216 due to the Company’s additional borrowing to complete the Riffe Field purchase in July 2008.

Comparison of the Six Months Ended June 30, 2009 and 2008.

The Company recognized $4,254,330 in revenues during the first six months of 2009 compared to $7,939,308 in the first six months of 2008. The decrease in revenues was again due to a dramatic decrease in oil prices in 2009. Oil prices in the first six months of 2009 averaged $44.13 per barrel compared to $104.37 per barrel in the first six months of 2008. The Company realized a net loss attributable to common shareholders of $(482,223) or $(0.01) per share of common stock during the first six months of 2009, compared to a net income in the first six months of 2008 to common shareholders of $7,233,718 or $0.12 per share of common stock. (Approximately $4.2 million [58%] of this income was attributable to the net effects of recognizing the Company’s deferred tax assets in 2008. The Company recorded the remaining net operating loss carry forwards of $5,227,000 in the first six months of 2008 and recorded non-cash income tax expense of $1,040,000 for the first six months net income. )

Production costs and taxes in the first six months of 2009 decreased to $2,374,289 from $2,743,137 in the first six months of 2008. The difference is due to the Company’s cost-cutting measures to control expenses due to the reduced prices for oil.

Depreciation, depletion, and amortization expense for the first six months of 2009 was $958,603 compared to $938,946 in the first six months of 2008. The depletion percentage has remained consistent with the total oil & gas properties.

Interest expense for the first six months of 2009 increased to $309,437 from $180,104 due to the additional borrowing for the Riffe field purchase in July 2008.

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Liquidity and Capital Resources

On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company. Under the facility as assigned to Sovereign, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $20 million or the Company’s borrowing base in effect from time to time. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment. 

On June 2, 2008, the Company entered into an amendment to its credit facility with Sovereign whereby the Company’s borrowing base was increased by the Bank as a result of its review of the Company’s currently owned producing properties.  The borrowing base was raised to $11 million effective June 2, 2008.  The Company had previously utilized about $4.2 million of the facility, leaving approximately $6.8 million then available for use by the Company upon this borrowing base increase.  The Company used $5.35 million of the then available $6.8 million for the purchase of the Riffe Field properties in Kansas.  The total borrowing by the Company under the facility as of the date of this Report is $9.9 million.

Effective February 5, 2009, the Company amended its credit facility with Sovereign to provide for a monthly reduction of the Bank’s commitment by $150,000 per month for the five month period of February through June 2008.  This commitment reduction is not a cash payment obligation of the Company but had the effect of reducing the Company’s available borrowing base in monthly increments of $150,000 so that by June 2009 the Company’s available borrowing base under the Sovereign facility was reduced by $750,000 from $11.0 million to $10.25 million. 

On July 9, 2009 the Company’s borrowing base was increased from $10.25 million to $11.0 million under the revolving senior credit facility between the Company and Sovereign. The Company’s borrowing base was increased on the completion of the regular semiannual borrowing base review by Sovereign. The $11.0 million borrowing base is again subject to a monthly available-credit reduction (MCR) of $150,000 per month beginning August 5, 2009, so that by the time of the next regular borrowing base review in six months, the borrowing base will again be $10.25 million. If the borrowing base under the Company’s Sovereign Bank revolving credit facility is reduced, the Company would be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility with Sovereign Bank.

On July 28, 2009 the Company entered into a two-year hedging agreement on crude oil pricing applicable to a portion of the Company’s crude oil production volumes.

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The agreement is effective beginning August 1, 2009. The “costless collar” hedge agreement has a $60.00 per barrel floor an $81.50 per barrel cap on a volume of 9,500 barrels per month during the period from August 1, 2009 through December 31, 2010, and 6,775 barrels per month from January 1 through July 31, 2011. To effectuate the hedge the Company entered into an International Swaps and Derivatives Master Agreement and an intercreditor agreement among the Company, its subsidiaries, Macquarie Bank Limited as counterparty, and Sovereign Bank of Dallas, Texas, the Company’s senior lender.

The Company pays no fee for this hedge agreement. If prices remain between the floor and ceiling prices, no activity occurs under the agreement. If crude oil prices are below $60.00 per barrel, the Company receives payment from the counterparty; if prices are above $81.50 per barrel, the Company makes payment to the counterparty on the hedged volumes of the Company’s oil production. The hedge is intended to provide some protection to the Company from any return to the levels of crude oil pricing as experienced in late 2008 and early 2009 when crude prices were in the $30 dollar per barrel range. The average price received by Tengasco in the first quarter of 2009 was $35.74 and $52.52 for the second quarter 2009. The hedge agreement operates to provide price support on the hedged volumes when market prices for crude oil are below $60.00 per barrel, but the upside potential on the hedged volumes if per barrel prices exceed $81.50 is lost to the Company. The Company’s current average production is about 15,000 barrels per month, so the downside protection on price would apply to only about two-thirds of current production. However, if market prices exceed $81.50 per barrel, the Company will receive that upside benefit as to the remaining one third of current production volumes that are above the hedged volume. This hedging agreement is primarily intended to help maintain and stabilize cash flow from operations if lower oil prices return, while providing at least some upside if prices increase above the hedge. If lower oil prices return, this agreement may help to maintain the Company’s production levels of crude oil by enabling the company to perform some ongoing polymer or other workover treatments on then-existing producing wells in Kansas.

Critical Accounting Policies

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

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Revenue Recognition

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

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all productive and non-productive costs incurred in connection with the acquisition of, exploration for, and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, day rate rentals, and the costs of drilling, completing and equipping oil and gas wells. However, costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties are excluded from the costs being amortized.

Oil and Gas Reserves/Depletion Depreciation

And Amortization of Oil and Gas Properties

The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.

The Company’s proved oil and gas reserves as of December 31, 2008 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production and timing of development expenditures includes many factors beyond the Company’s control.

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

Asset Retirement Obligations

The Company is required to record the effects of contractual or other legal obligations on well abandonments for capping and plugging wells. Management periodically reviews the estimate of the timing of the wells’ closures as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 8%. Quarterly, management accretes the 8% discount into the liability and makes other adjustments to the liability for well retirements incurred during the period.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT            MARKET RISKS     

The Company’s Borrowing Base under its

The borrowing base under the Company’s revolving credit facility with Sovereign Bank will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves. If cash flow from operations or the Company’s borrowing base decrease for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected. As a result, the Company’s ability to replace production may be limited. In addition, if the borrowing base under the Company’s Sovereign Bank revolving credit facility is reduced, the Company would be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility with Sovereign Bank. As of June 30, 2009, the Company’s current borrowing base is set at $11 million of which $9.9 million has been borrowed by the Company.

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Commodity Risk

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of $31.69 per barrel to a high of $127.29 per barrel during 2008 and an average of $44.13 for 2009. Gas price realizations ranged from a monthly low of $6.47 per Mcf to a monthly high of $13.21 per Mcf during the same period. The Company did not enter into any hedging agreements in the first six months of 2009 or 2008 to limit exposure to oil and gas price fluctuations. The Company did enter into a hedging agreement on July 28, 2009 limiting exposure to fluctuations in oil prices for a two year period beginning August 1, 2009. As that agreement applies to only approximately two thirds of the Company’s oil production, based on 2008 figures, it does not protect against all oil pricing fluctuations.

Interest Rate Risk

At June 30, 2009, the Company had debt outstanding of $10,177,963 including, as of that date, $9,900,000 owed on its credit facility with Sovereign. The interest rate on the Sovereign credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s debt owed to other parties of $277,963 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2008 fluctuated based on short-term interest rates on approximately 98% of its total debt. The annual impact on interest expense and the Company’s cash flows of a 10% increase in the interest rate on the Sovereign Credit facility would be approximately $59,400 assuming borrowed amounts under the Sovereign credit facility remained at the same amount owed as of December 31, 2008. The Company did not have any open derivative contracts relating to interest rates at December 31, 2008 or June 30, 2009.

Forward-Looking Statements and Risk

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company's control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost

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overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows.

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Principal Financial Officer, and other members of management team have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Securities Exchange Act of 1934, as amended (the ‘Exchange Act”). Based on such evaluation, the Company’s Chief Executive Officer and Principal Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. The effectiveness of a system of disclosure controls and procedures is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of internal controls, and fraud. Due to such inherent limitations, there can be no assurance that any system of disclosure controls and procedures will be successful in preventing all errors or fraud, or in making all material information known in a timely manner to the appropriate levels of management.

Changes in Internal Controls

During the period covered by this Report, there have been no changes to the Company’s system of internal control over financial reporting that have materially affected, or is reasonably likely to materially affect, the Company’s system of controls over financial reporting.

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

PART II OTHER INFORMATION

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) The annual meeting of stockholders of the Company was held on June 1, 2009.

(b) The first item voted upon was the election of Directors. Matthew K. Behrent, Jeffrey R. Bailey, John A. Clendening, Carlos P. Salas, and Peter E. Salas as Directors of the Company for a term of one year or until their successors are elected and qualified. The results of voting were as follows: 51,446,715 votes for Matthew K. Behrent and 1,515,633 withheld; 51,543,015 votes for Jeffrey R. Bailey and 1,419,333 withheld; 51,470,133 votes for John A. Clendening and 1,492,215 withheld; 51,128,796 votes for Carlos P. Salas and 1,833,552 withheld; and, 51,231,766 votes for Peter E. Salas and 1,730,582 withheld.

A plurality of votes at the meeting having voted for each of them, Messrs. Matthew K. Behrent, Jeffrey R. Bailey, John A. Clendening, Carlos P. Salas, and Peter E. Salas were duly elected as Directors of the Company.

(c) The second item voted on was a proposal to ratify the appointment by the Audit Committee of the Board of Directors of Rodefer Moss & Co, PLLC to serve as the independent certified public accountants of the Company for fiscal 2009.The results of the voting were as follows:

A majority of the votes cast at the meeting having voted for the proposal, the proposal was duly passed.

No other matters were voted upon at the meeting.

The Company’s subsidiary Manufactured Methane Corporation, (“MMC”) initiated startup of commercial operations as of April 1, 2009 at its Carter Valley, Tennessee methane gas extraction plant located at a landfill owned by Republic Services, Inc. During the month of April, the facility produced and sold 14,057,000 cubic feet of methane gas and was online about 91% of the calendar month. System maintenance and landfill supply adjustments accounted for the remainder of the time. On May 1, 2009, Eastman advised MMC that it was temporarily suspending deliveries of the methane gas stream pending approval by the federal Environmental Protection Agency (EPA) of Eastman’s petition for inclusion of treated methane gas as natural gas within the meaning of the EPA’s continuous emission monitoring rules applicable to Eastman’s large boilers

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during the annual “smog season” beginning May 1 of each year. Although Eastman had begun seeking this approval with the assistance of the Air Quality department of the Tennessee Department of Environment and Conservation in February, 2009, the EPA had not acted by May 1. Eastman has furnished to the EPA information provided by MMC that establishes that the methane gas stream is better fuel under the rule standards than even “natural” gas, which is technically defined to include gas being “found in geologic formations beneath the earth’s surface”. Eastman’s application is still pending as of the date of this report.   On August 3, 2009 MMC resumed sales of methane gas at Carter Valley in Tennessee to Hawkins County Gas Utility District, on a month to month basis.  MMC continues to look for additional ways to maximize the value of the methane gas produced, as management believes its derivation from a renewable energy source and its environmental benefit combine to make it a premium product.

As of the date of this report, EPA still has not acted on Eastman’s petition and accordingly sales to Eastman have not resumed. The Company has concluded an agreement for local sale of the methane gas to a local utility commencing August 1, 2009 on a month to month basis until either sales to Eastman may resume or other customers may be located by the Company.

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31.1 Certification of the Chief Executive Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a.

31.2 Certification of Chief Financial Officer, pursuant Exchange Act Rule, Rule 13a-14a/15d-14.

32.1 Certification of the Chief Executive Officer, pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

Dated: August 10, 2009

TENGASCO, INC.

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I, Jeffrey R. Bailey, certify that:

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f) for the registrant and we have:

(a)        designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;          

(b)        designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter ( the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and   

5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)        All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.        

Dated: August 10, 2009

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

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I, Mark A. Ruth, certify that:

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f) for the registrant and we have:

(a)        designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)        designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter ( the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and   

5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)        All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)  Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.        

Dated: August 10, 2009

By: s/ Mark A. Ruth

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Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009.

To the best of my knowledge this Quarterly Report on Form 10-Q (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

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Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended June 30, 2009.

To the best of my knowledge this Quarterly Report on Form 10-Q (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

Dated: August 10, 2009

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