Riley Exploration Permian, Inc. - Quarter Report: 2008 September (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 September 30, 2008
 
 

Commission File No. 001-15555

Tengasco, Inc. and Subsidiaries

(Exact name of issuer as specified in its charter)
 
 
 

10215 Technology Drive N.W. 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.
Yes X No__

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: 59,350,661 common shares at November 5 , 2008

TENGASCO, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

See accompanying notes to condensed consolidated financial statements

3

     See accompanying notes to condensed consolidated financial statements 

4    

See accompanying notes to condensed consolidated financial statements

5

See accompanying notes to condensed consolidated financial statements

6

See accompanying notes to condensed consolidated financial statements

7

Tengasco, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(1)    Basis of Presentation

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 nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ended December 31, 2008. 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, 2007.

(2)    Deferred Tax Benefit

Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income. The Company has had recurring taxable income for its last three fiscal years and for the first three quarters of 2008. As of January 1, 2008, the Company had available approximately $21,000,000 of net operating loss carry forwards to offset future taxable income. During the three months ended March 31, 2008, Management, using the “more likely than not” criteria for recognition, determined that it would be likely to realize the benefit of all of its net operating loss carry forwards and accordingly recognized a deferred tax benefit of $5,227,000. This resulted in total deferred tax assets of $7,327,000, at March 31, 2008, $2,100,000 of this amount having been previously recorded in 2007. The deferred tax assets are being amortized as applied against future taxable income with $1,845,000 of the tax benefit being amortized in the first nine months of 2008. At September 30, 2008, deferred tax assets approximated $5,482,000. The recognition of the deferred tax asset in 2008 will provide a better matching of income tax expense with taxable income in future periods.

8

(3)    Earnings per Share

In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,296,242 and 59,138,832 weighted average shares outstanding for the quarters ended September 30, 2008 and September 30, 2007 respectively and 59,214,498 and 59,105,871 weighted average shares for the nine months ended September 30, 2008 and September 30, 2007 respectively. Diluted earnings per common share are computed by dividing income available to common shareholders by the weighted-average number of shares of common stock outstanding during the period increased to include the number of additional shares of common stock that would have been outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options and warrants is reflected in diluted earnings per share. Dilutive shares outstanding at September 30, 2008 were 2,304,000, related to outstanding options and warrants.

(4)    Recent Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 had no impact on our results of operations or financial position. The Company currently has open tax return periods beginning with December 31, 2005 through December 31, 2007.

In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB

9

108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.

In September 2006, the FASB issued No. SFAS 157, “Fair Value Measurements” (“SFAS 157”). The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. 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.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — as amended (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company considered the applicability of SFAS 159 and determined not to adopt it at this time.

(5)     Related Party Transactions

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. ("Hoactzin") for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Program”). Peter E. Salas, the chairman of the Board of Directors of the Company is the controlling person of Hoactzin. Mr. Salas 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. Under the terms of the Program, Hoactzin was to pay the Company $400,000 for each well in the Program completed as a producing well and $250,000 per drilled well that was non-productive. The terms of Program also provide that Hoactzin will receive all the working interest in the ten wells in the Program, but will pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but, as defined, is in the nature of a net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of working interest revenues when and if net revenues received by

10

Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Program. The Company accounted for funds received for interests in the Program as an offset to oil and gas properties and no gain or loss was recognized from these transactions.

As of June 30, 2008, the Company had drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 97 barrels per day in total. Hoactzin paid a total of $3,850,000 for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.8 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 Program wells 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 the methane extraction project being developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation, (“MMC”) to the Payout Point. (The methane extraction project is discussed in greater detail below.) 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 Program, pursuant to an additional agreement with the Company was conveyed a 75% net profits interest in the methane extraction project being developed by “MMC” at the Carter Valley landfill owned and operated by BFI Waste Systems of Tennessee, LLC ("BFI") in Church Hill, Tennessee (the "Methane Project"). When the Methane Project comes online, the revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the 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.

11

The Company also announced that on September 17, 2007 it 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 Program (the “Purchase Price”) 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. At the end of the third quarter the amount of net revenues received by Hoactzin from the Program has reduced its obligation for the amount of the funds it had advanced for the Purchase Price from $3,850,000 to $2,145,203. The conversion option would be set at issuance of the preferred stock at the then twenty business day trailing average closing price of Company stock on the American Stock Exchange. Hoactzin has a similar option each year after 2009 in which Hoactzin’s then-unrecovered Purchase Price at the beginning of the year is not reduced 20% further by the end of that year, using the same conversion option calculation at date of the subsequent year’s issuance if any. The Company, however, may in any year make a cash payment from any source in the amount required to prevent such an exchange option for preferred stock from arising. In addition, the conversion right is limited to no more than 19% of the outstanding common shares of the Company. In the event Hoactzin’s 75% net profits interest in the Methane Project were fully exchanged for preferred stock, by definition the reduction of that 75% interest to a 7.5% net profits interest that was agreed to occur upon the receipt of 1.3547 of the Purchase Price by Hoactzin could not happen because the larger percentage interest then exchanged, no longer exists to be reduced. Accordingly, Hoactzin would retain no net profits interest in the Methane Project after a full exchange of Hoactzin’s 75% net profits interest for preferred stock.

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

12

However, with the successful results of the Program that the payout of 25% of the Purchase Price has already been reached, therefore no requirement to issue preferred stock will arise in 2010 or any preceding years.

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On that same date, the Company also entered into an agreement with Charles Patrick McInturff employing him as a Vice-President of the Company. Pursuant to the Management Agreement with Hoactzin, Mr. McInturff’s duties while he is employed as Vice-President of the Company will include the management on behalf of Hoactzin of its working interests in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As consideration for the Company entering into the Management Agreement, Hoactzin has agreed that it will be responsible to reimburse the Company for the payment of one-half of Mr. McInturff’s salary, as well as certain other benefits he receives during his employment by the Company. In further consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin has granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The term of the Management Agreement is the earlier of the date Hoactzin sells its interests in its managed properties or 5 years.

(6)     Oil and Gas Properties

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

13

The Company recorded $900,000 in depletion expense for the first nine months of 2008 and $825,000 in the first nine months of 2007.

(7)     Asset Retirement Obligation

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 6%, an estimated useful life of wells ranging from 30-40 years and an estimated plugging and abandonment cost range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.

(8)     Restricted Cash

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

(9)     Bank Loan

On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas (“Sovereign Bank”). Under our credit facility with Sovereign Bank of Dallas (“Sovereign”), loans and letters of credit will be available to the Company on a revolving basis in an amount not to exceed the lesser of $20 million or the Company’s borrowing base in effect from time to time. 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.

The Company’s initial borrowing on December 17, 2007 under its facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline as well as the Company’s Methane Project assets.

The borrowing base under the Company’s revolving credit facility with Sovereign Bank is currently set at 11 million and will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices.

14

The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000.The balance of approximately $825,000 was used to pay a portion of the purchase price of equipment to be utilized in the Methane Project currently under construction in Carter’s Valley, Tennessee by MMC, the Company’s wholly-owned subsidiary. The Company borrowed an additional $500,000 bringing the total to $4.7 million in the second quarter of 2008 to accelerate drilling on its Kansas properties in the second quarter of 2008. On July 1, 2008 the Company borrowed an additional $5.2 million for the Black Diamond purchase for a total as of September 30, 2008 of $9.9 million. See Item 3 for Market Risk disclosure.

(10)     Methane Project

On October 24, 2006 the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC (“BFI”). 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 municipal solid waste landfill in Carter’s Valley in Church Hill, Tennessee serving the metropolitan area of Kingsport, Tennessee that is owned and operated by BFI. BFI’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). The Company is installing a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream.  Methane is the principal component of natural gas and makes up about half of the purchased gas stream by volume. The Company is constructing a small diameter pipeline to deliver the extracted methane gas to the Company’s existing pipeline for delivery to Eastman (the “Methane Project”).

MMC has received delivery of all process equipment for the Methane Project, compressors needed to operate the process equipment, and the thermal oxidizer for destruction of byproducts from the methane extraction process. Electrical and utility interconnections are essentially complete on site. It is anticipated that the total costs for the Methane Project including pipeline construction, will total approximately $4.1 million including costs for compression and interstage controls. The costs of the Methane Project have been funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million, (b) cash flow from the Company’s operations in the amount of approximately $1 million and (c) $825,000 of the funds the Company borrowed from its credit facility with Sovereign Bank. The Company anticipates that the remaining balance of the Methane Project costs will be paid from the Company’s cash flow.

The installation of all of Manufactured Methane Corporation’s project equipment and three-mile gas pipeline at Allied Waste’s Carter Valley Landfill in Church Hill, Tennessee is completed as of the date of this Report. The methane extraction process equipment has been inspected by the respective manufacturers’ engineers in preparation

15

for startup of operations. The Company anticipates that after initial startup and calibration of equipment is completed, that the Company will be in the position to commence commercial deliveries of the extracted methane gas stream into the Company’s existing gas pipeline system by December, 2008. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company (“Eastman”) under the terms of the Company’s existing natural gas purchase and sale agreement. At current gas production rates and expected extraction efficiencies, when commercial operations of the Project begin, the Company expects to deliver about 418 MMBtu per day of additional gas to Eastman, which would substantially increase the current volumes of natural gas being delivered to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas of $7 per MMBtu, near the average natural gas price received by the Company in 2007, the anticipated net profits to the Company would be approximately $800,000 per year from the Methane Project based on anticipated volumes and expenses. Initially 75% of the net profits in the Methane Project would be paid to Hoactzin as agreed with the Company and applied to reaching the Payout Point or “flip” point where Hoactzin’s interest in the Drilling Program and the Methane Project are reduced, and the Company’s interests correspondingly increased. The gas supply from the Methane Project is projected to grow over the years as the underlying operating landfill continues to expand and generate additional naturally produced gas, and for several years following the closing of the landfill, currently estimated by BFI to occur between the years 2022 and 2026.

As part of the Methane Project agreement, the Company agreed to install a new force-main water drainage line for Allied Waste Industries, an affiliate of BFI, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations of pipeline. 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 began in January 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, requires no additional permits for the gas pipeline construction.

(11)   Black Diamond Purchase
 

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

16

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

Results of Operations and Financial Condition

Kansas

During the first nine months of 2008, the Company sold 165,782 gross barrels of oil from its Kansas Properties that currently comprise 170 producing oil wells. Of the 165,782 gross barrels, 109,494 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 nine months of 2008 of 109,494 net barrels of oil compares to 96,747 barrels sold to the Company’s interest in the first nine months of 2007. The Company’s net revenues from the Kansas properties were $12,115,669 in the first nine months of 2008 compared to $5,831,906 in 2007. This increase was due to an increase in prices for oil to an average of $106.53 in 2008 from an average of $60.28 in 2007 and a 12,747 net barrel increase in sales in 2008. This 12% increase in production is due to a 10% increase on properties owned before the addition of the Riffe field, generated from drilling and polymer work-overs. The three months of production from the newly acquired Riffe Field contributed 2% to the 9 month total.

  Tennessee

During the first nine months of 2008, the Company produced gas from 23 wells in the Swan Creek field, which it primarily sold in Kingsport, Tennessee to Eastman Chemical Company. Natural gas production from the Swan Creek field for the first nine months of 2008 was an average of 234 Mcf per day during that period as compared to 207 Mcf per day in the first nine months of 2007. For the first nine months of 2008, the Company produced 4,247 barrels of oil from the Swan Creek field as compared to 5,729 in the first nine months of 2007.

Comparison of the Quarters Ended September 30, 2008 and 2007.

The Company recognized $5,067,106 in revenues during the third quarter of 2008 compared to $2,375,229 in the third quarter of 2007. The increase in revenues was due to an increase in oil prices in 2008 and a 9,377 net barrel increase in oil sales. Oil prices in the third quarter of 2008 averaged $110.85 per barrel as compared to $69.15 per barrel in the third quarter of 2007. Although the Company’s gross revenues increased substantially, the Company’s net income attributable to common shareholders of $1,562,967 or $0.03 per share of common stock during the third quarter of 2008 was relatively the same as the net income in the third quarter of 2007 to common shareholders of $1,580,662 or $0.03 per share of common stock. This was due to a tax expense of $805,000 for the third quarter of 2008.The Company's operating income was $2,367,967 in 2008 compared to operating income in 2007 of $480,662. The Company recorded a operating loss carry forwards of $1,100,000 in the third quarter of 2007 and recorded non-cash income tax expense of $805,000 for the third quarter net income of 2008.

17

Production costs and taxes in the third quarter of 2008 increased to $1,472,913 from $990,489 in the third quarter of 2007. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry. These costs have increased with the rise in fuel costs and commodity price increases.

Depreciation, depletion, and amortization expense for the third quarter of 2008 was $552,165 compared to $479,487 in the third quarter of 2007. The depletion has remained consistent even though revenues have increased proportionally to increase in oil prices. The Company increased depletion in 2008 to account for the Black Diamond purchase.

During the third quarter of 2008, general and administrative costs increased to $418,985 from $291,680 in the third quarter of 2007 due to continued administrative growth.

Interest expense increased from $94,014 in 2007 to $214,548 in 2008, due to additional borrowing and an increase in asset retirement obligation due to the Black Diamond purchase.

Comparison of the Nine Months Ended September 30, 2008 and 2007.

The Company recognized $13,006,414 in revenues during the first nine months of 2008 compared to $6,368,068 in the first nine months of 2007. The increase in revenues was due to an increase in oil prices in 2008 and a 12,747 net barrel increase in oil sales. Oil prices in the first nine months of 2008 averaged $106.53 per barrel as compared to $60.28 per barrel in the first nine months of 2007. The Company realized a net income attributable to common shareholders of $8,796,685 or $0.15 per share of common stock during the first nine months of 2008, compared to a net income in the first nine months of 2007 to common shareholders of $1,702,253 or $0.03 per share of common stock. Approximately $3.4 million (38%) of this income was attributable to the net effects of recognizing the Company’s deferred tax assets in 2008. The Company's operating income was $5,414,685 in 2008 compared to operating income in 2007 of $602,253. The Company recorded the remaining net operating loss carry forwards of $5,227,000 in the first quarter of 2008 and recorded non-cash income tax expense of $1,845,000 for the first nine months net income. The Company recorded $1,100,000 in operating loss carry forwards in 2007.

Production costs and taxes in the first nine months of 2008 increased to $4,216,050 from $2,902,595 in the first nine months of 2007. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry. These cost have increased due to the rise in fuel costs and commodity price increases.

Depreciation, depletion, and amortization expense for the first nine months of 2008 was $1,491,111 compared to $1,422,845 in the first nine months of 2007. The depletion has remained consistent even though revenues have increased proportionally to price.

18

During the first nine months of 2008, general and administrative costs increased to $1,228,477 from $989,176 in the first nine months of 2007 due to continued administrative growth.

Interest expense increased from $245,606 in 2007 to $394,652 due to additional borrowing and an increase in asset retirement obligation from the Black Diamond purchase.

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 will be 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 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. The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. 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 used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Church Hill, Tennessee by MMC, the Company’s wholly-owned subsidiary. The Company borrowed an additional $500,000 in the second quarter of 2008 to accelerate drilling activities on its Kansas Properties.

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

19

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.
 

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. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center.

Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties are excluded from the costs being amortized. No ceiling write-downs were recorded in 2008 or 2007.

20

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, 2007 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production and timing of development expenditures includes many factors beyond the Company’s control.

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

     Asset Retirement Obligations

The Company 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’ closure as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 6%. Quarterly, management accretes the 6% 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

      Credit Facility may be reduced by Sovereign Bank.

     The borrowing base under the Company’s revolving credit facility with Sovereign Bank will be determined from time to time by the lender, 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 lenders' inability to agree to an adequate borrowing base or adverse changes in the lenders' practices regarding estimation of reserves. If cash flow from operations or the

21

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, it 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 September 30, 2008 the Company’s current borrowing base is set at $11 million dollars of which $9.9 million has been drawn down by the Company.

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 $49.05 per barrel to a high of $89.18 per barrel during 2007 to an average of $106.53 in 2008. Gas price realizations ranged from a monthly low of $5.43 per Mcf to a monthly high of $7.59 per Mcf during the same period. The Company did not enter into any hedging agreements in 2008 or 2007 to limit exposure to oil and gas price fluctuations.

Interest Rate Risk

At September 30, 2008, the Company had debt outstanding of $10,058,114 including, as of that date, $9,900,000 owed on its credit facility with Sovereign Bank. 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 $158,114 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2007 fluctuated based on short-term interest rates on approximately 96% of its total debt outstanding at December 31, 2007. The impact on interest expense and the Company’s cash flows of a 10 percent increase in the interest rate on the Sovereign Credit facility would be approximately $25,273, assuming borrowed amounts under the Sovereign credit facility remained at the same amount owed as of December 31, 2007. The Company did not have any open derivative contracts relating to interest rates at December 31, 2007 or for 2008.

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,

22

economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low

prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows.
 

ITEM 4T. CONTROLS AND PROCEDURES

      Controls and Procedures

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 Exchange Act Rules 13a-15(e) and 15d-15(e)). 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 has 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.

23

PART II OTHER INFORMATION

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

During the third quarter of fiscal 2008, the Company issued 148,820 unregistered and restricted shares of its common stock pursuant to the exercise of warrants issued by the Company to members of the plaintiff class as part of the settlement of the action entitled Paul Miller v. M. E. Ratliff and Tengasco, Inc., United States District Court for the Eastern District of Tennessee, Knoxville, Docket Number 3:02-CV-644. Those warrants were exercisable for a period of three years from date of issue at $0.45 per share and the warrants themselves are exempt from registration pursuant to Section 3(a) (10) of the Securities Act of 1933. These warrants expired on September 12, 2008.

ITEM 5. OTHER INFORMATION
 

The installation of all of Manufactured Methane Corporation’s project equipment and three-mile gas pipeline at the Carter Valley Landfill in Church Hill, Tennessee is completed as of the date of this Report. The methane extraction process equipment has been inspected by the respective manufacturers’ engineers in preparation for startup of operations. The Company anticipates that after initial startup and calibration of equipment is completed, that the Company will be in the position to commence commercial deliveries of the extracted methane gas stream into the Company’s existing gas pipeline system by December, 2008. In the third quarter the Company drilled four wells, while weather and rig availability pushed the drilling of some locations into the fourth quarter. The first of these four wells was the Albers #1 wildcat discovery well drilled in early July that started producing on July 29th, 2008 and has produced 4000 barrels to date a 42 barrels of oil per day average through November 1st. The second well, the McClure, was a wildcat well drilled in Rooks County that was a dry hole. The third well, the Verveka C #1 is a water disposal well drilled to handle the water being produced in our ongoing drilling program targeting the Verveka lease. This general area contains many future locations and establishing water management was critical to allow future development. For example, an offset well, the Verveka B #1 drilled earlier this year, has produced 1375 barrels and needs access to a water disposal location. However, after the Company treated it with polymers, the Verveka B #1 has seen decreased water production, and in the first 4 days of production after the polymer treatment has produced more than 450 barrels of oil. The fourth well drilled was the Zerger #1, another offset to the Verveka Lease. Production of this well is being held up waiting on final clearance to use the Verveka C #1 disposal well. The company has more than 15 future locations in this area of focus that will be the target of a significant portion of the near future drilling sites. In October 2008, the Company returned to Trego County to drill the Albers A #1 as an offset to the original Albers well. The new well has tested productively and this will be completed soon.

The Riffe field production that was purchased in July, has yielded immediate benefits to the Company’s production levels. We purchased these properties when they

24

were producing about 80 barrels per day. We have performed two polymer treatments on existing Riffe field wells, and are completing a third one. As a result, current production from the Riffe field properties has increased to approximately 135 barrels per day average for October, and at the time of this release the Riffe field was producing over 185 barrels per day on the strength of another polymer application. All in all this leaves our gross oil production rate the first week of November well above 800 barrels per day.

During the third quarter the Company worked toward completion of the Company’s methane extraction process at the Carter Valley landfill in Hawkins County, Tennessee. As of November 1, 2008 the plant equipment installation and the three mile gas pipeline connection to our existing line are complete. The Company is now in initial testing and calibration for startup and expects that commercial deliveries of methane should begin in early December 2008. These gas volumes will supplement the Company’s gas production from the Swan Creek field and it is anticipated that this project will approximately double our current daily production volumes of gas.”

25

ITEM 6 EXHIBITS

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.

26

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: November 10, 2008

TENGASCO, INC.

     By: s/ Jeffrey R. Bailey
     Jeffrey R. Bailey
     Chief Executive Officer
 
 
 
     By: s/ Mark A. Ruth
     Mark A. Ruth
     Chief Financial Officer

27

Exhibit 31.1 CERTIFICATION

I, Jeffrey R. Bailey, certify that:

     1. I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September, 2008.
     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;     

          
          (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: November 10, 2008

By: s/ Jeffrey R. Bailey
Jeffrey R. Bailey
Chief Executive Officer 

28

Exhibit 31.2      CERTIFICATION

I, Mark A. Ruth, certify that:
 
     1. I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September30, 2008.
 
     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;     

          
          (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: November 10, 2008

By: s/ Mark A. Ruth
Mark A. Ruth
Chief Financial Officer

29

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 September 30, 2008.

        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 present, 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: November 10, 2008 

30

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 September 30, 2008.

        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 present, 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: November 10, 2008
 
 

31