Riley Exploration Permian, Inc. - Quarter Report: 2007 September (Form 10-Q)

outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options and warrants is reflected in diluted earnings per share.

Dilutive shares outstanding at September 30, 2007 were 1,821,510, related to outstanding options and warrants and 1,403,931 for September 30, 2006.

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. 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 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 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 continues to evaluate 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 — 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.

 

(5)	Related Party Transactions

 

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 Management 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 then outstanding 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 under 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. Hoactzin will continue to

 

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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. 

 

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, LP (“Hoactzin”) for ten wells to be drilled in Kansas targeting production of oil during the remainder of 2007. Under the drilling program, Hoactzin will pay $400,000 per well completed as a producer, and $250,000 per drilled well that is nonproductive. The total purchase price will consequently be between $2.5 million and $4 million. The controlling person of Hoactzin is Peter E. Salas, the Chairman of the Company’s Board of Directors and also the controlling person of Dolphin Offshore Partners, LP, the Company’s largest shareholder. On September 17, 2007 the Audit Committee of the Company’s Board of Directors, as well as the Board of Directors, authorized the transactions in accordance with the Company’s related party transaction policy.

 

Under the terms of the drilling program, Hoactzin will receive all the working interest in the ten wells, but will pay an initial management fee to the Company of 25% of its working interest revenues net of operating expenses. The management fee paid by Hoactzin will increase to 85% of working interest revenues when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price paid for the drilling program.

 

On September 17, 2007 Hoactzin was simultaneously conveyed a 75% net profits interest in the Company’s subsidiary Manufactured Methane Corporation’s Carter Valley, Tennessee methane extraction project. When the methane project comes online, the methane project revenues received by Hoactzin will also apply towards the determination of the payout point for the drilling program. When the payout point is reached from either the drilled wells or the methane project, Hoactzin’s net profits interest in this methane project will decrease to a 7.5% net profits interest.

 

The Company also announced that on September 17, 2007 it entered into an additional agreement with Hoactzin providing that if the new drilling program wells and the methane project interest in combination failed to return net revenues to Hoactzin equal to 25% of the actual drilling program purchase price by December 31, 2009, then Hoactzin has an option to exchange up to 20% of its net profits interest in the methane project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the drilling program price less the net proceeds received at the time of any exchange. Hoactzin has a similar option each year after 2009 in which Hoactzin’s unrecovered investment at the beginning of the year is not reduced 20% further by the end of that year. The Company, however, may in any year make a cash payment in the amount required to prevent such an exchange option for preferred stock from arising.

 

 

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(6)	Oil and Gas Properties

 

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

 

	September 30, 2007	December 31, 2006
Oil and gas properties, at cost	$  19,781,306	$  18,745,834
Unevaluated properties	2,674,806	1,880,811
Accumulation depreciation, depletion and amortization	(8,748,016)	(7,923,016)
Oil and gas properties, net	$  13,708,096	$  12,703,629

 

The Company recorded $825,000 in depletion expense for the first nine months of 2007 and $750,000 in the first nine months of 2006.

 

(7)	Asset Retirement Obligation

 

The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of estimated 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 recognized 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 depending on well characteristics evaluated on a case by case basis. Management continues to periodically evaluate the appropriateness of these assumptions.

 

(8)	Restricted Cash

 

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

 

(9)

Bank Loan

 

On 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.

 

 

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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 2006. This amount will be amortized over the term of the Citibank note.

 

On April 19, 2007 the Company borrowed an 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.    

 

(10)	Methane Project

 

The Company expects commercial production from the Carter Valley methane project to begin in 2008 subject to equipment production schedules and completion of construction of a 2.5 mile pipeline. As of September 30, 2007 the Company has paid from cash flow $795,710 in equipment costs and has placed orders for the two main equipment modules needed for the Carter Valley methane project.

 

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

 

Results of Operations and Financial Condition

 

 

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Kansas

 

During the first nine months of 2007, the Company sold 137,265 gross barrels of oil from its Kansas Properties comprised of 146 producing oil wells. Of the 137,265 gross barrels, 96,747 barrels were net to the Company after required payments to all of the Drilling Program participants and royalty interests. The Company’s sales for the first nine months of 2007 of 96,747 net barrels of oil compares to 88,808 barrels sold to the Company’s interest in the first nine months of 2006. The Company’s net revenues from the Kansas properties were $5,831,906 in the first nine months of 2007 compared to $5,589,577 in 2006. The increase in revenues relates to the 7,939 barrels net increase in sales volumes as the nine month average price in 2006 was $62.94 as compared to $60.28 in 2007. The Company’s production was affected by inclement weather in Kansas in the first quarter of 2007.

 

Tennessee

 

During the first nine 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 nine months of 2007 was an average of 207 Mcf per day during that period as compared to 401 Mcf per day in the first nine months of 2006. The first nine 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 nine months of 2007 the Company produced 5,729 barrels of oil as compared to 6,587 in the first nine months of 2006.

 

Comparison of the Quarters Ended September 30, 2007 and 2006

 

The Company recognized $2,375,229 in revenues from its Kansas Properties and the Swan Creek field during the third quarter of 2007 compared to $2,251,274 in the third quarter of 2006. The increase in revenues was mainly due to a 4,584 net barrels increase in oil sales for the quarter and a $4.18 increase in price from the third quarter of 2006. Theses increases were offset by an 18,729 Mcf net decrease in gas sales. Oil prices in the third quarter of 2007 averaged $69.15 per barrel as compared to $64.97 per barrel in the third quarter of 2006. The Company realized a net income attributable to common shareholders of $1,580,662 or $0.03 per share of common stock during the third quarter of 2007, compared to a net income in the third quarter of 2006 to common shareholders of $519,094 or $0.01 per share of common stock. The Company recognized a tax benefit for NOL carry forwards in the amount of $1,100,000 in the third quarter of 2007.

 

Production costs and taxes in the third quarter of 2007 increased to $990,489 from $732,473 in the third quarter of 2006. 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 third quarter of 2007 remained consistent at $479,487 compared to $503,665 in the third quarter of 2006.

 

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During the third quarter of 2007, general and administrative costs decreased to $291,680 from $384,245 in the third quarter of 2006.

 

Professional fees in the third quarter of 2007 were $38,099 compared to $13,376 in the same period in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 3 of the Regulation S-K.

 

Interest expense for the third quarter of 2007 remained consistent at $94,014 compared to $97,318 in the third quarter of 2006.

 

Comparison of the Nine Months Ended September 30, 2007 and 2006

 

The Company recognized $6,368,068 in total revenues from its Kansas Properties and the Swan Creek Field during the first nine months of 2007 compared to $6,704,979 in the first nine months of 2006. The decrease in revenues was due to a decrease in Swan Creek gas sales of 51,901 Mcf along with a decrease in gas prices, also a decrease in oil prices in 2007 which was partially offset by Kansas oil sales increase during this period of 7,939 net bbls which is attributable to well workovers, polymer completion workovers and the Company’s portion of an eight-well drilling program. Oil prices in the first nine months of 2007 averaged $60.28 per barrel as compared to $62.94 per barrel in the first nine months of 2006.

 

The Company realized a net income attributable to common shareholders of $1,702,253 or $0.03 per share of common stock during the first nine months of 2007, compared to a net income in the first nine months of 2006 to common shareholders of $1,556,210 or $0.03 per share of common stock. The Company recognized a tax benefit for NOL carry forwards in the amount of $1,100,000 in the third quarter of 2007.

 

Production costs and taxes in the first nine months of 2007 increased to $2,902,595 from $2,399,324 in the first nine months of 2006. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry.

 

Depletion, depreciation, and amortization expense for the first nine months of 2007 were $1,422,841 compared to $1,315,445 in the first nine months of 2006. The increase relates to depletion taken on Oil and Gas Properties.

 

During the first nine months of 2007, general and administrative costs decreased to $989,176 from $1,122,091.

 

Professional fees in the first nine months of 2007 were $186,458 compared to $140,370 in the same period in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 3 of Regulation S-K.

 

 

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Interest expense for the first nine months of 2007 increased to $245,606 from $146,355 in the first nine months of 2006. The increase relates to the Citibank Loan, as the Citibank loan was not in place until June 29 of 2006.

 

Liquidity and Capital Resources

 

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. On April 19, 2007 as a result of periodic review under the credit facility, the borrowing base was increased to $3.3 million, and the Company borrowed an additional amount of $700,000 which was used for development of the Company’s producing properties.

 

Critical Accounting Policies

 

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

 

Revenue Recognition

 

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

 

Full Cost Method of Accounting

 

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and non-productive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, day rate rentals and the costs of drilling, completing and equipping oil and gas wells. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also

capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost

 

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center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties that 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.                      

 

Asset Retirement Obligations

 

The Company is required to record the effects of contractual or other legal obligations on well abandonments for capping and plugging wells. Management periodically reviews the estimate of the timing of the wells’ closure as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 12%. Quarterly, management accretes the 12% 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 $51.74 per barrel to a high of $68.82 per 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 September 30, 2007, the Company had debt outstanding of $3,496,226 including, as of that date, $3,300,000 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 $196,226 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 $27,225. The Company did not have any open derivative contracts relating to interest rates at December 31, 2006 or September 30, 2007.

 

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.

 

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ITEM 4

CONTROLS AND PROCEDURES

 

Controls and Procedures

 

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 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 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 third quarter of fiscal 2007, the Company issued 213 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

 

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years from date of issue at $0.45 per share and the warrants themselves are exempt from registration pursuant to Section 3(a) (10) of the Securities Act of 1933.

 

ITEM 5   OTHER INFORMATION

 

During the third quarter the Company drilled six gross wells in Kansas. Four of these wells are owned entirely by the Company: Howard #1, Hobrock #5, Veverka #1 and the Gilliand #1, and the other two wells are part of the Company’s ten-well drilling program in which the company receives 25% plus an additional interest after payout: the Stahl A#1, and the Croffoot AA#1. During October, 2007 the Company drilled three additional wells under the drilling program, the Croffoot BB #1, Veverka A#1, and the Howard #2.

 

The results as of the date of this report are:

Howard #1 plugged and abandoned July 4, 2007.

Hobrock #5 completed August 7, 2007and is currently producing approximately 14 barrels per day.

Veverka #1 plugged and abandoned August 17, 2007

Gilliand #1 plugged and abandoned August 28, 2007

 

Drilling program results:

Stahl A #1 completed October 13, 2007 currently producing approximately 14 barrels per day.

Crofoot AA#1 completed October 19, 2007 currently producing approximately 20 barrels per day.

Veverka A #1 drilled October 11, 2007 completed but awaiting pumping unit installation.

Croffoot BB #1 drilled October 20, 2007 Completion attempt is in progress.

Howard #2 has been drilled on November 8, 2007 it was a dry hole and was plugged and abandoned.

 

Two additional wells are permitted for drilling in November 2007: the Nutsch, and the Green. Both wells will be a part of the ten well program.

 

The Company’s wholly owned subsidiary, Manufactured Methane Corporation, has placed equipment orders for its first stage of process equipment (cleanup and carbon dioxide removal) and the second stage of process equipment (nitrogen rejection.) as of the date of this Report, the Company has paid approximately $950,000 in equipment costs for this project from the Company’s cash flow. Total project costs, including pipeline construction, are expected to be approximately $3.7 million. The Company now anticipates that equipment will be manufactured and delivered to allow operations to begin in the April or May 2008 time period when equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed.

 

 

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As part of the project agreement, the Company has agreed to install a new force-main water drainage line for Allied Waste, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations of pipeline. Allied Waste will be responsible for the additional costs for the water line. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline is expected to begin upon receipt of permits from Tennessee state and local wastewater authorities in connection with the drainage line. Those permit applications were submitted by Allied Waste in late July, 2007 and have been approved in part. The Company expects the remaining permits to be acted upon promptly. As a certificated utility, the Company’s pipeline subsidiary requires no additional permits for the gas pipeline construction. The Company currently anticipates that pipeline construction will be concluded approximately the same time as equipment deliveries and installation occurs, subject to grant of permits and weather delays during winter construction.

 

 

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ITEM 6

EXHIBITS

 

(a)

The following exhibits are filed with this report:

 

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.

 

 

SIGNATURES

 

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

 

Dated: November 9, 2007

 

TENGASCO, INC.

 

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

 

 

By: s/ Mark A. Ruth

Mark A. Ruth

Chief Financial Officer

 

 

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Exhibit 31.1

CERTIFICATION

I, Jeffrey R. Bailey

1.    I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September 30, 2007.

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: November 9, 2007

 

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

 

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Exhibit 31.2

CERTIFICATION

I, Mark A. Ruth, certify that:

1.  I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September 30, 2007.

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: November 9, 2007

 

By: s/ Mark A. Ruth

Mark A. Ruth

Chief Financial Officer

 

 

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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 September 30, 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 present, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

Dated: November 9, 2007

 

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

 

 

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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 September 30, 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 present, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

Dated: November 9, 2007

 

 

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

 

 

 

 

 

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