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, 2007

 

Commission File No. 0-20975

 

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, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Check One:

 

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: 59,138,705 common shares at May 1, 2007.

 

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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

(Unaudited)

 

 

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, 2007 are not necessarily indicative of the results that may be expected for the year ended December 31, 2007. No income tax expense was recognized for the three months ended March 31, 2007 because deferred tax benefits, derived from the Company’s prior net operating losses, were previously fully-reserved and are being offset against liabilities that would otherwise arise from the results of current operations. Additionally, deferred income tax assets and liabilities are not reflected in the Company’s financial statements. Management continuously estimates the realization of its deferred tax assets based on its assessment of the likely timing and adequacy of future net income that will be generated from sales in a volatile commodity market, at prices over which the Company has no control. Based on its assessment, for each of the three months ending March 31, 2007 and 2006, management reserved the gross tax benefit. 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, 2006.

 

 

In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,047,979 and 58,605,109 weighted average shares outstanding for the quarters ended March 31, 2007 and March 31, 2006 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.

 

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Dilutive shares outstanding at March 31, 2006 were 1,328,610, 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 December 2004, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), (SFAS 123(R)) “Share Based Payment”. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 (APB 25), “Accounting for Stock Issued to Employees”, and generally requires that such transactions be accounted for using a fair-value-based method. This statement is effective for fiscal years beginning after June 15, 2005. SFAS 123(R) applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date and as a consequence future employee stock option grants and other stock based compensation plans are now recorded as expense over the vesting period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) was recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company has recognized stock-based compensation expense from July 1, 2005 as if the fair value based accounting method had been used to account for all outstanding unvested employee awards granted, modified or settled in prior years. The Company adopted SFAS 123(R) in 2005 and recognized $26,815 in compensation expense in the first quarter of 2007 for options granted and $53,374 in 2006. The Company will recognize $107,260 in 2007 and 2008 in compensation expense relating to these options granted. The ultimate impact on results of operation and financial position in future years will depend upon the level of stock-based compensation granted.

 

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

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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. We do not expect the interpretation will have a material impact on our results of operations or financial position.

 

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 a impact on 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 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 Company is currently evaluating the impact the adoption of this statement could have on its 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 — Including an Amendment of FASB 115” (“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. The Company believes that adopting SFAS 159 will not result in any material effect on their financial position or operating results.

 

 

 

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On October 5, 2005, Hoactzin Partners, L.P. ("Hoactzin") surrendered to the Company two outstanding promissory notes dated May 19, 2005 and August 22, 2005 made by the Company to Dolphin Offshore Partners. L.P. (“Dolphin”) in the aggregate principal amount of $2,514,000. Peter E. Salas who is Chairman of the Company’s Board of Directors is the sole shareholder and controlling person of Dolphin Managemnt Inc., the general partner of Dolphin. Mr. Salas is also the controlling person of Hoactzin. In exchange for the surrender of these notes, the Company entered into an agreement granting Hoactzin a 94.3% working interest in a 12-well drilling program to be undertaken by the Company on its properties in Kansas. The Company retained the remaining 5.7% working interest in the drilling program.

 

On June 29, 2006 the Company used $1.393 million of the proceeds of a $2.6 million loan from Citibank Texas, N.A. to exercise the Company’s option to repurchase from Hoactzin the Company’s obligation to drill for Hoactzin the final six wells of the Company’s 12-well Kansas drilling program. 

 

If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the program until payout as established in the terms of the drilling program.  However, as a result of the terms of the repurchase option exercised by the Company, Hoactzin will receive only a 6.25% overriding royalty in the next six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six program wells that have previously been drilled.  As a further result of the repurchase, the 12-well program was converted into a 6-well program, and because six wells have already been drilled by the Company as of June 30, 2006 the drilling obligation in this program was satisfied. Hoactizin will continue to receive its agreed upon revenues allocable to its working interest until payout under the program occurs, at which time the Company will begin to receive a management fee of 85% of Hoatzin’s working interest proceeds for the remaining life of the six program wells. 

 

 

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

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The Company recorded $275,000 in depletion expense for the first three months of 2007 and $225,000 in the first three months of 2006.

 

 

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 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 12%, 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.

 

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On June 29, 2006 the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks.

 

Under the facility, 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 $50,000,000 or the borrowing base in effect from time to time. The Company’s initial borrowing base was set at $2,600,000. The initial loan under the facility with Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing interest at a floating rate equal to LIBOR plus 2.5%, resulting in an initial rate of interest of approximately 8.2%. Interest only is payable during the term of the loan and the principal balance of the loan is due thirty-six months from closing. The facility is secured by a lien on substantially all of the Company’s producing and non-producing oil and gas properties and pipeline assets. The facility has standard loan covenants such as current ratios, and interest coverage ratios, etc., with which the Company is in compliance. $1.393 million of the $2.6 million loan proceeds were used by the Company on June 29, 2006 to exercise its option to repurchase from Hoactzin Partners, L.P., the Company’s obligation to drill the final six wells in the Company’s 12-well Kansas drilling program for Hoactzin. The Company incurred closing costs consisting of legal fees, mortgage taxes, commissions and bank fees in connection with the Citibank facility of $285,224 in the first quarter of 2007. This amount will be amortized over the term of the Citibank note.

 

 

On April 19, 2007 the Company borrowed the additional sum of $700,000 from Citibank, N.A. under its existing revolving credit facility dated June 29, 2006.   The additional borrowing resulted from an increase in the Company’s borrowing base under the Citibank credit facility from $2.6 million to $3.3 million based upon Citibank’s periodic review of the Company’s borrowing base.  With the additional borrowing, the Company has borrowed the full amount of its $3.3 million borrowing base under the revolving Citibank credit facility. Repayment of this additional sum is subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed will be used for further development of the Company’s producing properties.    

 

 

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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 2007, the Company sold 42,415 gross barrels of oil from its Kansas Properties comprised of 143 producing oil wells. Of the 42,415 gross barrels, 29,418 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 2007 of 29,418 net barrels of oil compares to 28,326 barrels sold to the Company’s interest in the first three months of 2006. The Company’s net revenues from the Kansas properties were $1,544,147 in the first three months of 2007 compared to $1,666,524 in 2006. This decrease was due to decrease in prices for oil from an average of $58.93 in 2006 to an average of $52.61 in 2007. The Company’s production was affected by inclement weather in Kansas. See Item 5 Other Information in this document.

 

 

During the first three months of 2007, 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 2007 was an average of 236 Mcf per day during that period as compared to 419 Mcf per day in the first three months of 2006. 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 2007 the Company produced 2,546 barrels of oil as compared to 2,320 in the first three months of 2006.

 

Comparison of the Quarters Ended March 31, 2007 and 2006.

 

The Company recognized $1,772,400 in revenues from its Kansas Properties and the Swan Creek field during the first quarter of 2007 compared to $2,098,969 in the first quarter of 2006. The decrease in revenues was due to a decrease in oil prices in 2007 and a 16,493 mcf net decrease in gas production. Despite record oil production the loss from the ice storm also affected total sales. Oil prices in the first quarter of 2007 averaged $52.61 per barrel as compared to $58.93 per barrel in the first quarter of 2006. The Company realized a net loss attributable to common shareholders of $(209,165) or $(0.00) per share of common stock during the first quarter of 2007, compared to a net income in the first quarter of 2006 to common shareholders of $316,347 or $0.01 per share of common stock. The Company’s revenue in the first quarter of 2007 was adversely affected by inclement weather in Kansas and lower oil prices.

 

 

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Production costs and taxes in the first quarter of 2007 increased to $963,130 from $855,510 in the first quarter of 2006. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry and also start up costs relating to power outages.

 

Depreciation, depletion, and amortization expense for the first quarter of 2007 was $476,051 compared to $405,886 in the first quarter of 2006, the increase mainly relates to depletion taken on oil and gas properties.

 

During the first quarter of 2007, general and administrative costs decreased to $345,588 from $398,225 in the first quarter of 2006.

 

Professional fees in the first quarter of 2007 were $125,379 compared to $99,200 in the same period in 2006.

 

Interest expense for the first quarter of 2007 increased to $71,023 from $22,089 in the first quarter of 2006. The increase relates to the Citibank loan.

 

Liquidity and Capital Resources

 

On October 5, 2005 the Company and Hoactzin Partners, L.P. (“Hoactzin”) signed an agreement whereby Hoactzin surrendered the two promissory notes made by the Company to Dolphin Offshore Partners, L.P. (“Dolphin”), the Company’s largest shareholder, in the amounts of $700,000 and $1,814,000 evidencing loans made by Dolphin to the Company to fund cash payments made by the Company to its former Series A, B and C preferred shareholders in exchange for their preferred stock. Peter E. Salas, the Chairman of the Company’s Board of Directors is the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin. Mr. Salas is also the controlling person of Hoactzin. In consideration for the surrender of these notes Hoactzin was granted a 94.275% working interest in new twelve well drilling program (the “Twelve Well Program”) on the Company’s properties in Kansas. The Company retained the 5.725% working interest in the Twelve Well Program not owned by Hoactzin. Under the terms of the Twelve Well Program, the Company retained an option expiring March 31, 2006 to repurchase from Hoactzin the obligations to drill the final six wells of the Twelve Well Program for one half of the principal of notes exchanged by Hoactzin, plus interest on that amount at 6% per annum until the date of any repurchase, plus a 1/16 overriding royalty to Hoactzin on all wells drilled in the Twelve Well Program. Payout and management fee calculations would also be adjusted to reflect any reduction to a six well program.

 

On June 29, 2006 the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks.  Under the facility, 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 $50,000,000 or the borrowing base in effect from time to time. The Company’s initial borrowing base was set at $2,600,000.  The initial loan under the facility with Citibank closed on June 29, 2006 in the principal amount of $2.6 million,

 

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bearing interest at a floating rate equal to LIBOR plus 2.5%, resulting in a current rate of interest of approximately 8.2%.  Interest only is payable during the term of the loan and the principal balance of the loan is due thirty-six months from closing.   The facility is secured by a lien on substantially all of the Company’s producing and non-producing oil and gas properties and pipeline assets.

 

On June 29, 2006 the Company used $1.393 million of the proceeds of the $2.6 million Citibank loan to exercise the Company’s option to repurchase from Hoactzin the Company’s obligation to drill the final six wells of the Company’s Twelve Well Program.  If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Twelve Well Program until payout as established under the terms of the Twelve Well Program.  However, as a result of the terms of the repurchase option, Hoactzin will receive only a 6.25% overriding royalty in the next six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six Program Wells that have previously been drilled.  As a further result of the repurchase, the Twelve Well Program was converted into a six well program, and because six wells had been drilled by the Company as of June 30, 2006 the drilling obligation in this program were satisfied upon exercise of the repurchase option.  Consequently, all well-drilling obligations of the Company owed to participants have been satisfied as to both the Twelve Well Program and earlier Eight Well Program that had been offered to the Company’s former Series A preferred stockholders (the “Eight Well Program”). Under the terms of those programs, upon payment to the participants of 80% of the value invested in the program from proceeds from production, the participants will pay the Company a management fee of 85% of the proceeds from their working interests. As to the Eight Well Program, that point was reached in April 2007 resulting in an expected increase in revenues from these wells to the Company of approximately $50,000 per month at current volumes and prices. As to the Twelve (now 6) Well Program, that point is expected to be reached some time in 2008 or 2009 depending upon prices and production levels experienced from the wells in that program.

 

As of December 31, 2006 the Company had completed a total reworking of its balance sheet that began in February 2004. During this period the Company has resolved all major litigation and eliminated the accompanying legal fees. The Company also had a successful rights offering which raised capital to pay off substantial debt.  The Company also sold its small block of gas properties in Kansas obtaining a dollar benefit of high gas prices reflected in the $2.4 million sales price while simultaneously eliminating the high operating expenses of those properties. The Company used proceeds of the gas property sale to further pay down debt. As a result, the Company’s long term debt has been substantially reduced.  The Company has also met its obligations to all of its preferred stockholders by exchanging their preferred stock either for cash, stock, or drilling program interests, and has accordingly cancelled all of the Series A, B, and C preferred stock it had issued. The Company has completed all of its well-drilling obligations to the drilling program participants out of its own cash flow from operations and without additional borrowing for drilling. As a result of the successful completion of this restructuring, the Company is now in a position to move forward focusing on the growth and development of its business. Accordingly, the Company continues to successfully rework

 

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existing wells, to drill new oil wells in Kansas and is acquiring additional lease acreage to increase production and to grow its reserves through the drill bit.  

 

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 recognizes revenues based on actual volumes of oil and gas sold and delivered to its customers. Natural gas meters are placed at the customers’ location and usage is billed each month. Crude oil is stored and at the time of delivery to the customers, revenues are recognized.

 

 

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

 

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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 2007 or 2006.

 

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, 2006 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 12%. Quarterly, management accretes the 12% 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

 

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 $51.74 per barrel to a high of $68.82 per

 

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barrel during 2006. Gas price realizations ranged from a monthly low of $4.20 per Mcf to a monthly high of $11.55 per Mcf during the same period. The Company did not enter into any hedging agreements in 2007 or 2006 to limit exposure to oil and gas price fluctuations.

 

Interest Rate Risk

 

At March 31, 2007, the Company had debt outstanding of $2,765,839 including, as of that date, $2,600,000 owed on its credit facility with Citibank Texas, N. A. The interest rate on the Citibank credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s debt owed to other parties of $165,839 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2006 fluctuated based on short-term interest rates on approximately 93% of its total debt outstanding at December 31, 2006. 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 $21,128, assuming borrowed amounts under the Citibank credit facility remained at the same amount owed as of December 31, 2006. 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 prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows.

 

 

 

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and

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Exchange Commission and that such information is accumulated and communicated to our management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. As of the end of the period covered by this Report, and under the supervision and with the participation of the management, including its Chief Executive Officer and Chief Financial Officer, management evaluated the effectiveness of the design and operation of these disclosure controls and procedures. Based on this evaluation and subject to the foregoing, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective in reaching a reasonable level of assurance of achieving management’s desired controls and procedures objectives.

 

Changes in Internal Controls  

 

During the period covered by this Report, there have not been any changes in the Company’s internal controls that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

 

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

 

PART II OTHER INFORMATION

 

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

During the first quarter of fiscal 2007, the Company issued 171 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 are exercisable for a period of three years from September 12, 2005 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, as amended.

 

During the first quarter of 2007, the Company issued 36,000 registered and unrestricted shares upon the exercise of options granted under the Tengasco, Inc. Incentive Stock Plan.

 

On February 2, 2007, the Company issued 5,500 shares of its unregistered and restricted common stock each to John A. Clendening, and Carlos Salas Directors of the

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Company and 8,250 shares to another Director, Clarke H. Bailey, for their services as members of the Company’s Audit Committee in Fiscal 2006. Mr. Bailey was the Chairman of the Committee and was designated by the Board of Directors as the Company’s “Audit Committee financial expert” as defined by applicable Securities and Exchange Commission regulations.

 

ITEM 5   OTHER INFORMATION

 

Historically, the first quarter of any year has been the most modest quarter of the year for the Company’s oil production in Kansas.  This year 2007 proved no different as Kansas experienced one of its worst ice storms in memory.  Many counties in Kansas, including some counties where the Company has wells, lost power for the entire month of January.  Producing wells in those counties were unable to produce without electricity to run the well pumps during the power outage.  Consequently in January 2007 the Company saw production and revenue decline from monthly levels in late 2006.  None of the Company’s producing wells were physically damaged by the ice storm or by non-production during the absence of power, but the storm did substantially adversely impact production levels and sales in the first two months of 2007 while at the same time causing an increase in expenses.  Eventually new poles and lines were rebuilt on a locally massive scale and electrical power was restored, and the Company experienced a rebound of production in March 2007.

 

Despite the significant ice storm impact experienced in January 2007, the Company posted record production volumes of oil in the first quarter of 2007.  The Company produced 40,503 barrels in the first quarter 2007 compared  to 38,502 barrels in the first quarter of 2006 which had been the previous production high for first quarter production. However, the erosion in pricing from 2006 to 2007 levels combined with the lost production from the ice storm, and associated repair costs reduced total revenues in the first quarter 2007 compared to the same period in 2006.  April 2007 sales of oil in Kansas, while not yet completely tabulated as of the date of this filing, have also rebounded above 16,000 barrels to follow the profitable March 2007 production rebound experienced after the effects of the January ice storm.

 

One wildcat well in Kansas was drilled by the Company in the first quarter of 2007 at a location selected based on seismic analysis drilling similar to the 15 successful wells the Company has drilled out of its last 18 drilled wells.  That well encountered noncommercial quantities of oil and was plugged.

 

Three Kansas wells targeting oil have been permitted by the Company for drilling in the second quarter of 2007.  The first one should spud in May, followed by two in June.

 

The Company has finished the design of the Vincent-Winterset seismic exploration program, our largest to date of 8,280 acres of Company-leased acreage.  The Company has been joined by other Kansas operators in this area adding their acreage to the

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program, making this project an estimated combined “group shoot” in excess of 100,000 acres.  This project should begin with collection of seismic data in the next thirty days. On completion of the shoot, the acquired data will then be prepared and analyzed for determination of potential productive drilling targets.

 

As a result of having reached in April 2007 the payback of their program investment as called for by the terms of their drilling program, the former Series “A” drilling program participants will now begin to pay an 85% management fee to the Company.  This has the effect of increasing the Company’s net interest in those program wells from about 19% to an effective 88% working interest in the six producing Kansas oil wells in that program.  

 

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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, 2007

 

TENGASCO, INC.

 

 

 

 

 

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I, Jeffrey R. Bailey

1.    I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended March 31, 2006.

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 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 officer(s) 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)) for the registrant and 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 know to us by others within those entities, particularly during the period in which this report is being prepared:

 

(b) 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;

 

(c) 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: May 14, 2007

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

 

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I, Mark A. Ruth, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended March 31, 2006.

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 quarterly 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 officer(s) 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)) for the registrant and 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 know to us by others within those entities, particularly during the period in which this report is being prepared:

 

(b)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;

 

(c) 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: May 14, 2007

 

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, 2007.

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

 

 

 

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Exhibit 32.2

CERTIFICATION

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

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended March 31, 2006.

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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