Riley Exploration Permian, Inc. - Quarter Report: 2008 March (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 March 31, 2008

 

Commission File No. 1-15555

 

Tengasco, Inc. and Subsidiaries

(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: 59,198,750common shares at May 1, 2008.

 

 

 

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TENGASCO, INC. AND SUBSIDIARIES

 

TABLE OF CONTENTS

 

 

 

 

 

 

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TENGASCO, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

ASSETS

 

 

 

 

See accompanying notes to condensed consolidated financial statements

 

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TENGASCO, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED BALANCE SHEETS

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

See accompanying notes to condensed consolidated financial statements

 

 

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TENGASCO, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements   

 

 

 

 

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TENGASCO, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

 

 

 

See accompanying notes to condensed consolidated financial statements

 

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TENGASCO, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

 

 

 

See accompanying notes to condensed consolidated financial statements

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Tengasco, Inc. and Subsidiaries

Notes to Condensed 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 three months ended March 31, 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.

 

 

The Company has taxable income for the periods ending December 31, 2007, December 31, 2006 and December 31, 2005 and the first quarter of 2008.

 

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. As of March 31, 2008, the Company had approximately $21,000,000 of net operating loss carry forwards. As of 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 to offset future federal taxable income and accordingly elected to recognize a deferred tax asset of $7,327,000, $2,100,000 of this amount having been previously recorded in 2007. This resulted in a tax benefit of $7,327,000 which will be amortized as used with future income. $300,000 of this tax benefit was amortized in the first quarter of 2008 The recognition of the deferred tax asset in 2008 will provide a better matching of income tax expense with taxable income in future periods.

 

The Company has recorded all of its net operating loss carry forwards of approximately $21,000,000 resulting in a tax benefit of $7,327,000 which will be amortized as used with future income.

 

 

In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,156,805 nd 59,047,979 weighted average shares outstanding for the quarters ended March 31, 2008

 

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and March 31, 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 March 31, 2008 were 1,787,048, related to outstanding options and warrants. For the period ended March 31, 2007, outstanding options and warrants are anti-dilutive due to the net loss for the quarter and, accordingly, are disregarded in the computation of dilutive shares outstanding.

 

 

In July 2006, the 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, 2004 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 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 SFAS 157, Fair Value Measurements. 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

 

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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. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS 157 had no significant impact on our financial position, results of operations or 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 is considering the applicability of SFAS 159 and will determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.

 

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 net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”). The Company has accounted for funds received for interests in the Program as an offset to oil and gas properties.

 

As of the date of this Report, the Company has drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 84 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

 

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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 are expected to reach the Payout Point in approximately four years solely from the oil revenues from the wells. However, under the terms of its agreement with Hoactzin the time for reaching the Payout Point likely will be accelerated by Hoactzin agreeing to 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, at the Carter Valley, Tennessee landfill 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, executed a separate agreement with the Company and was conveyed a 7.5% net profits interest in a methane extraction project being developed by the Company's wholly-owned subsidiary, Manufactured Methane Corporation ("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, initially 75% of the net 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 payments under its net profits interest in the Methane Project will return to 7.5% net profits interest. The Company believes that the application of revenues from the Methane Project to reach the Payout Point could accelerate reaching the Payout Point. As stated above, the price paid by Hoactzin for its interest in the Program exceeded the Company’s anticipated and actual costs of drilling the ten wells in the Program. Those excess funds provided by Hoactzin were used to pay for approximately $1,000,000 of equipment required for the Methane Project, or about 25% of the Project’s capital costs. The availability of the funds provided by Hoactzin eliminated the need for the Company to borrow those funds, to have to pay interest to any lending institution making such loans or to dedicate Company revenues or revenues from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the Company as a favorable element to the Company of the overall transaction.

 

The Company also announced that on September 17, 2007 it entered into an additional agreement with Hoactzin providing that if the 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 has an option to exchange up to 20% of its net profits interest in the Methane Project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the

 

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Purchase Price less the net proceeds received at the time of any exchange. At the time the agreement was executed, the Company's forecast of the probable results of the projects indicated that there was little risk that Hoactzin's contingent option to acquire preferred stock would ever arise, so the Company placed no significant value to the preferred stock option. The number of shares issuable under the contingent option to acquire preferred stock is to be determined based on the then twenty business day trailing average closing price of Company common stock on the American Stock Exchange. Each share of the Company's convertible preferred stock would then be convertible to one share of the Company's registered or unregistered common stock. 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 that Hoactzin’s proceeds from the drilling and methane projects fail to satisfy the payout point requirements for any period or in its entirety and Hoactzin's contingent option is triggered, should Hoactzin elect to exercise its contingent option to acquire convertible preferred shares in the Company, then that portion exercised permanently reduces Hoactzin's interest in the methane project, up to its entirety, if so elected.

 

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 convertible at the trailing average price before each year’s issuance of the preferred. The maximum number of common shares into which all such preferred could be converted cannot be calculated given the formulaic determination of conversion price based on future stock price. However, for purposes of a calculation example only, assume a consistent trailing average stock price of $.75 per common share, and that Hoactzin's payout point is $3.7 million. Hoactzin could then elect to exchange its interest for 4.93 million shares of preferred stock which would then be convertible into 8.35% of the Company’s currently outstanding shares.

 

However, the Company anticipates that with the demonstrated successful results of the Program that the payout of 25% of the Purchase Price will be reached by December 31, 2009 and Hoactzin option to exchange its interest for contigent preferred shares would not be triggered in 2010. The Company further anticipates that at current oil and gas prices, and at currently expected sales levels of methane gas from the Methane Project to come online in 2008, that the balance of the unrecovered Purchase Price by Hoactzin will also be reduced by at least 20% each year thereafter. Based only on current production from the nine producing wells in the Program (i.e. not considering any revenue contribution from the Methane Project), expected decline curves for production, and using current oil prices, the Company expects that by December 2009, Hoactzin will have received approximately 66% of the Purchase Price, far in excess of the 25%

 

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required in order to obviate any occasion to exchange its interest in the Methane Project for preferred stock. As a result, the Company believes it is a remote probability that the Hoactzin contingent option to acquire preferred stock will be triggered under the terms of this agreement at any time in the future.

 

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.

 

 

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

 

 

The Company recorded $275,000 in depletion expense for the first three months of 2008 and $275,000 in the first three months of 2007.

 

 

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. Additionally, SFAS 143 required that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would

 

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have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. 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, 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.

 

 

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 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 Carter Valley, Tennessee by MMC, the Company’s wholly-owned subsidiary.

 

 

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

 

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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 Valley serving the metropolitan area of Kingsport, Tennessee that is owned and operated by BFI in Church Hill, Tennessee. BFI’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). 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”).

 

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

 

The Company anticipates that operation of the Methane Project will begin in mid-2008 after equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company (“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 revenues to the Company would be approximately $800,000 per year from the Methane Project based on anticipated volumes and expenses. The gas supply from the 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

 

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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. The Company currently anticipates that pipeline construction will be concluded approximately the same time as equipment deliveries and installations occur or in the May to June 2008 time period, subject to weather delays during wintertime construction.

 

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

 

Results of Operations and Financial Condition

 

Kansas

 

During the first three months of 2008, the Company sold 49,272 gross barrels of oil from its Kansas Properties comprised of 149 producing oil wells. Of the 49,272 gross barrels, 34,764 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 three months of 2008 of 34,764 net barrels of oil compares to 29,418 barrels sold to the Company’s interest in the first three months of 2007. The Company’s net revenues from the Kansas properties were $3,080,721 in the first three months of 2008 compared to $1,544,147 in 2007. This increase was due to an increase in prices for oil from an average of $91.36 in 2008 to an average of $52.61 in 2007 and a 5,346 net barrel increase in sales in 2008. In addition, the Company’s production during the first three months of 2007 was adversely affected by severe inclement weather in Kansas.

 

 

During the first three 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 three months of 2008 was an average of 195 Mcf per day during that period as compared to 236 Mcf per day in the first three months of 2007. The first three months production reflected expected natural decline in production from the existing Swan Creek gas wells which were first brought into production in mid-2001 upon completion of the Company’s pipeline. For the first three months of 2008, the Company produced 1,424 barrels of oil from the swan creek field as compared to 2,546 in the first three months of 2007.

 

Comparison of the Quarters Ended March 31, 2008 and 2007.

 

The Company recognized $3,305,720 in revenues from its Kansas Properties and the Swan Creek field during the first quarter of 2008 compared to $1,772,400

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in the first quarter of 2007. The increase in revenues was due to an increase in oil prices in 2008 and a 5,346 net barrel increase in oil sales. Oil prices in the first quarter of 2008 averaged $91.36 per barrel as compared to $52.61 per barrel in the first quarter of 2007. The Company realized a net income attributable to common shareholders of $5,812,011 or $0.10 per share of common stock during the first quarter of 2008, compared to a net loss in the first quarter of 2007 to common shareholders of $(209,165) or $0.00 per share of common stock. The Company's operating income was $885,011 or .02 per share in 2008 compared to a loss in operating income in 2007 of ($209,165). The Company recorded the remaining net operating loss carry forwards of $5,227,000 in the first quarter of 2008 and recorded income tax expense of $300,000 for the first quarter net income. This resulted in an .08 per share net income. The Company’s revenue in the first quarter of 2007 was adversely affected by inclement weather in Kansas and lower oil prices. Production costs and taxes in the first quarter of 2008 increased to $1,335,021 from $963,130 in the first quarter of 2007. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry.

 

Depreciation, depletion, and amortization expense for the first quarter of 2008 was $465,300 compared to $476,051 in the first quarter of 2007.

 

During the first quarter of 2008, general and administrative costs increased to $397,607 from $345,588 in the first quarter of 2007.

 

Professional fees in the first quarter of 2008 were $97,628 compared to $125,379 in the same period in 2007.

 

Interest expense for the first quarter of 2008 increased to $107,888 from $71,023 in the first quarter of 2007. The increase relates to the Sovereign loan.

 

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.

 

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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’s cash balance at year-end of $2,226,839 was attributable to high commodity prices as well as an increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the Ten Well Program. The Company has expended approximately $1.5 million of these funds subsequent to year-end on the Methane Project and completing the Ten Well Program.

 

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.

 

 

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.

 

 

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.

 

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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.

 

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.             

 

 

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.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS 

 

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 an average of $91.36 in the 1^st quarter of 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 March 31, 2008, the Company had debt outstanding of $4,374,544 including, as of that date, $4,212,105 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 $162,439 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 Citibank Credit facility would be approximately $25,273, assuming borrowed amounts under the Citibank 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, 2006.

 

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 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

 

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

 

ITEM 4T 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.

 

Management’s Report on Internal Control over Financial Reporting

 

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Internal control over financial reporting refers to the process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer, and effected by the Company’s Board of Directors, management and other personnel, 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, and includes those policies and procedures that:

 

 

•          Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and

 

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Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of March 31, 2008 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring organizations of the Treadway Commission (“COSO”). Based on the evaluation conducted under the framework in “Internal Control – Integrated Framework,” issued by COSO the Company’s management concluded that the Company’s internal control over financial reporting was effective as of March 31, 2008.

 

This report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Form 10-Q.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

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.

 

 

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PART II OTHER INFORMATION

 

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

During the first quarter of 2008, the Company issued 3,000 registered and unrestricted shares upon the exercise of options granted under the Tengasco, Inc. Incentive Stock Plan.

 

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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: May 14, 2008

 

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):

 

 

Dated: May 14, 2008

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:

 

(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):

 

 

Dated: May 14, 2008

 

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 March 31, 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 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.

 

 

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 March 31, 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 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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