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U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2016

Commission File No. 1-15555

(Exact name of registrant as specified in its charter)

 

6021 S. Syracuse Way, Suite 117, Greenwood Village, CO 80111

(Address of principal executive offices)

720-420-4460

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ☒   No ☐

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   ☒ Yes    ☐ No

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 6,093,634 common shares at August 8, 2016.

 

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TABLE OF CONTENTS

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands, except share and per share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(1)	Description of Business and Significant Accounting Policies

Tengasco, Inc. (the “Company”) is a Delaware corporation.  The Company is in the business of exploration for and production of oil and natural gas.  The Company’s primary area of exploration and production is in Kansas.

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operates a treatment facility for the extraction of methane gas from nonconventional sources for eventual sale to natural gas customers or generation of electricity.  This facility is located at the Carter Valley landfill site in Church Hill, Tennessee.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) 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 U.S. GAAP for complete financial statements, although the Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01.  Operating results for the six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the year ended December 31, 2016. It is suggested that these condensed consolidated financial statements be read in conjunction with 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, 2015.

Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances.

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairment of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Revenue Recognition

Revenues are recognized based on actual volumes of oil, natural gas, methane, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.  Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.  There were no natural gas imbalances at June 30, 2016 or December 31, 2015.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and any sales of methane or electricity are billed each month.  No methane gas was sold during the six months ended June 30, 2016 or 2015.

Cash and Cash Equivalents

Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.

Inventory

Inventory consists of crude oil in tanks and is carried at lower of cost or market value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended June 30, 2016 and December 31, 2015.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The market component is calculated using the average June 2016 and December 2015 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or market value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The market component is based on estimated sales value for similar equipment and materials as of June 30, 2016 and December 31, 2015.  The following table sets forth information concerning the Company’s inventory (in thousands):

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

 

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 costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd.  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 had unevaluated properties of $552,000 at June 30, 2016 and December 31, 2015.  Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down cannot be reversed in a later period.  During the three months and six months ended June 30, 2016, the Company recorded an impairment of oil and gas properties in the amount of $1,445,000 and $2,086,000, respectively.  No impairment of oil and gas properties were recorded during the three months and six months ended June 30, 2015.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at June 30, 2016 and December 31, 2015.

The following table sets forth information concerning the Company’s accounts receivable (in thousands):

 

(2)	Income Taxes

The Company uses the asset and liability method of accounting for deferred income taxes.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities.  Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The deferred income tax assets or liabilities for an oil and gas exploration and development company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices.  Accordingly, the asset or liability is subject to continuous recalculation, and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

 

The Company does not expect to pay any federal or state income tax for the year 2016 as a result of net operating loss carry forwards from prior years.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some or all of the benefits of deferred tax assets will not be realized.  As of June 30, 2016, the Company has recorded a full valuation allowance on its deferred tax assets.  Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes.  There were no recorded unrecognized tax benefits at June 30, 2016.

(3)	Earnings per Common Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (in thousands except for share and per share amounts):

 

Share and per share data at June 30, 2015 has been adjusted to reflect the impact of the 1 for 10 reverse stock split approved at the shareholder meeting on March 21, 2016, effective with trading on March 24, 2016.  The total number of shares issued and outstanding represent estimates after adjustments to reflect the impact of the reverse stock split.

(4)	Recent Accounting Pronouncements

In August 2014, the FASB issued Update No. 2014-15—Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  This was issued to provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The guidance is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. Early application is permitted.  The Company does not expect this to impact its operating results or cash flows.

In November 2015, the FASB issued ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.  This guidance eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent.  This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  The amendments may be applied prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented.  The Company does not expect this to impact its operating results or cash flows.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

In February 2016, the FASB issued Update 2016-02—Leases (Topic 842).  This guidance was issued to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.  Early application of the amendments in this Update is permitted for all entities.  The Company does not expect this to impact its operating results or cash flows.

In March 2016, the FASB issued Update 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.  This guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period.  The Company does not expect this to impact operating results or cash flows.

(5)	Related Party Transactions

On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Ten Well Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He was also at the time the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which was the Company’s largest shareholder at that time.

Under the terms of the Ten Well Program, Hoactzin paid the Company $0.4 million for each well drilled in the Ten Well Program completed as a producing well and $0.25 million for each well that was non-productive. The terms of the Ten Well Program also provided that Hoactzin would receive all the working interest in the ten wells in the Program, but would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses.  This is referred to as a management fee but, as defined, is in the nature of a net profits interest.  The fee paid to the Company by Hoactzin would increase to 85% if net revenues received by Hoactzin reached an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Ten Well Program.

In March 2008, the Company drilled and completed the final well in the Ten Well Program. Hoactzin paid a total of $3.85 million (the “Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being determined as $5.2 million.

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, was conveyed a 75% net profits interest in the methane extraction project developed by MMC at the Carter Valley landfill owned by Republic Services in Church Hill, Tennessee (the "Methane Project"). Net profits, if any, from the Methane Project received by Hoactzin would have been applied towards the determination of the Payout Point for the Ten Well Program.  However, through March 31, 2016, no payments were made to Hoactzin for its net profits interest in the Methane Project, because no net profits were generated.

The method of calculation of the net profits interest takes into account specific costs and expenses as well as gross gas revenues for the Methane Project.  As a result of the startup costs and ongoing operating expenses, no net profits, as defined in the agreement, have been generated from startup in April, 2009 through June 30, 2016 for payment to Hoactzin under the net profits interest conveyed.

In February 2014, net revenues earned by Hoactzin from the Ten Well Program had exceeded $5.2 million and thereby reached the Payout Point which increased the management fee due to the Company by Hoactzin from 25% to 85% and reduced the net profits interest in the Methane Project from 75% to 7.5%.

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, offshore Texas, and offshore Louisiana (the “Management Agreement”).

As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement.  The Management Agreement terminated by its own terms on December 18, 2012.  The Company is assisting Hoactzin with becoming operator of record of these wells.  The Company has entered into a transition agreement with Hoactzin whereby Hoactzin and its controlling member indemnify the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of record on certain of these wells.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

During the course of the Management Agreement, the Company became the operator of certain properties owned by Hoactzin.  The Company obtained from IndemCo, over time, bonds in the face amount of approximately $10.7 million for the purpose of covering plugging and abandonment obligations for Hoactzin’s operated properties located in federal offshore waters in favor of the BSEE, as well as certain private parties.  In connection with the issuance of these bonds the Company signed a Payment and Indemnity Agreement with IndemCo whereby the Company guaranteed payment of any bonding liabilities incurred by IndemCo. Dolphin Direct Equity Partners, LP also signed the Payment and Indemnity Agreement, thereby becoming jointly and severally liable with the Company for the obligations to IndemCo.  Dolphin Direct Equity Partners, L.P. is a private equity fund controlled by Peter E. Salas that has a significant economic interest in Hoactzin. Hoactzin had provided $6.6 million in cash to IndemCo as collateral for these potential obligations.  As of May 15, 2014, all bonds issued by IndemCo and subject to the Payment and Indemnity Agreement have been released by the BSEE and have been cancelled by IndemCo.  Accordingly, the exposure to the Company under any of the now cancelled IndemCo bonds or the indemnity agreement relating to those now cancelled bonds has decreased to zero.

As part of the transition process, Hoactzin secured new bonds from Argonaut Insurance Company to replace the IndemCo bonds.  As noted above, all of the IndemCo bonds were replaced, and all IndemCo bonds were cancelled.  Also as part of the transition to Hoactzin becoming named operator of its own properties, four separate right-of-use and easement (“RUE”) bonds in the aggregate amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as then-current operator.  Hoactzin and Dolphin Direct signed an indemnity agreement with Argonaut as well as provided the required collateral for the new Argonaut bonds, including 100% cash collateral for the four RUE bonds issued in the Company’s name.  The Company was not party to the indemnity agreement with Argonaut and has not provided any collateral for any of the Argonaut bonds issued.  As of the date of this Report, all of these four RUE bonds have been cancelled and released by the Bureau of Ocean Energy Management as to the Company.  Accordingly, the transfer from the Company to Hoactzin of all interests in and obligations under these four RUE’s and associated bonding is now completed.

As operator, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties.  In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name.  During late 2009 and early 2010, Hoactzin undertook several significant operations, for which the Company contracted in the ordinary course.  As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet.  Payables related to these past due and ongoing operations remained outstanding at June 30, 2016 and December 31, 2015 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of June 30, 2016 and December 31, 2015 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to establish an allowance in the amount of $159,000 for the balances outstanding at June 30, 2016 and December 31, 2015.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” is $0 at June 30, 2016 and December 31, 2015.

The Company has entered into an agreement with Hoactzin whereby Hoactzin and Dolphin Direct are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is still the operator of record on certain of these wells.  Until such time as Hoactzin becomes operator of record on these wells and the corresponding bonding liability is transferred from the Company to Hoactzin, per the transition agreement, the Company had suspended drilling payments to Hoactzin.  As of December 31, 2015, the Company had suspended approximately $634,000 in payments.  This balance of these suspended payments is recorded in the Consolidated Balance Sheet under “Accounts payable – related party”.  In January 2016, the Company paid these held funds to Hoactzin.

The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to collateralize the appeal bond with RLI Insurance Company and to pay the civil penalty and interest thereon.  See Note 11. Commitments and Contingencies.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(6)	Oil and Gas Properties

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

 

The Company recorded depletion expense of $583,000 and $1,360,000 for the six months ended June 30, 2016 and 2015, respectively.  In addition, during the six months ended June 30, 2016, the Company recorded an impairment of oil and gas properties in the amount of $2,086,000.  No impairment of oil and gas properties was recorded during the six months ended June 30, 2015.  As a result of the ceiling test impairment, the accumulated depreciation, depletion, and amortization has been netted against the cost to reflect the post impairment value of the oil and gas properties.

(7)	Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the six months ended June 30, 2016 (in thousands):

 

 

(8)	Long-Term Debt

Long-term debt to unrelated entities consisted of the following (in thousands):

 

Unamortized debt issuance cost at December 31, 2015 was reclassified from an asset to a reduction of long-term debt.  This reclassification was done to comply with ASU 2015-03 Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

On March 28, 2016, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to decrease the Company’s borrowing base from $7.8 million to approximately $3.2 million, extend the term of the facility to January 30, 2018, and delete the Leverage Ratio covenant.  For the quarter ended December 31, 2015, the Company was in default on compliance with the Leverage Ratio covenant.  In addition, the amendment also added a Debt to Tangible Net Worth covenant, waived the default on the Interest Coverage ratio for the quarter ended December 31, 2015, waived the anticipated default for the quarter ended March 31, 2016, and waived compliance with the Interest Coverage ratio for all applicable periods through the maturity date.  Although the Company was in default of the Leverage and Interest Coverage ratios for the quarter ended December 31, 2015, the Company was in compliance at March 28, 2016 as a result of the amendment and waivers.  For the quarter ended June 30, 2016, the Company was in default on compliance with the Debt to Tangible Net Worth covenant.  On August 10, 2016, the Company received a waiver of the covenant default for the quarter ended June 30, 2016 as well as a waiver for the anticipated default for the quarter ended September 30, 2016.  Based on additional means of raising capital currently being considered by the Company, it is anticipated that the Company will be in compliance with this covenant for the quarter ended December 31, 2016.  Although the Company was in default of the Debt to Tangible Net Worth covenant for the quarter ended June 30, 2016, the Company was in compliance as of August 10, 2016 as a result of the waiver.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 4.00% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million.  The next borrowing base review will take place in August 2016.

(9)	Manufactured Methane

The following table sets forth information concerning the Manufactured Methane facilities (in thousands):

 

The methane facilities were placed into service on April 1, 2009.  The methane facilities are being depreciated over the estimated useful life of approximately 33 years based on estimated landfill closure date of December 2041.  The Company recorded depreciation expense of $30,000 for the six months ended June 30, 2016 and 2015.

(10)	Fair Value Measurements

FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:

Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data.  If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management.  The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions.

 

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of June 30, 2016 and December 31, 2015.

 

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(11)	Commitments and Contingencies

The Company as designated operator was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s properties.  This action calls for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011.  In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty.   This appeal required a fully collateralized appeal bond to postpone the payment obligation until the appeal was determined.  The Company posted and collateralized this bond with RLI Insurance Company.  If the bond was not posted, the appeal would have been administratively denied and the order to the Company as operator to pay the $386,000 penalty would have become final.  On June 23, 2014, the IBLA affirmed the civil penalty without reduction.  On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans.  On July 14, 2015, the court affirmed the determination by the IBLA without reduction.  The Company determined that further appeal of the determination was not likely to reduce the penalty and the Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty affirmed on appeal and statutory interest thereon from funds borrowed under its credit facility.  The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.

During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement.  This analysis raised issues other than the “Incident of Non-Compliance” discussed above.  The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended June 30, 2016, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if he is still employed by the Company or still a member of the Board of Directors.  As of June 30, 2016, the reductions were approximately $162,000.  The Company has not accrued any liabilities associated with these compensation reductions.

 

ITEM 2.

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

Results of Operations and Financial Condition

During the first six months of 2016, 70.5 MBbl gross of oil were sold from the Company’s properties.  Of the 70.5 MBbl, 55.5 MBbl were net to the Company after required payments to all of the royalty interests and drilling program participants.  The Company’s net sales from its properties during the first six months of 2016 of 55.5 MBbl of oil compares to net sales of 69.6 MBbl of oil during the first six months of 2015.  The Company’s net revenue from its oil and gas properties was $1.9 million during the first six months of 2016 compared to $3.3 million during the first six months of 2015.  This decrease in net revenue was primarily due to a $716,000 decrease related to a $12.90 per barrel decrease in the average oil price from $46.64 per barrel during the first six months of 2015 to $33.75 per barrel during the first six months of 2016, and a $658,000 decrease related to the 14.1 MBbl decrease in sales volumes.  The 14.1 MBbl decrease was primarily due to decreased sales volumes from the Albers, Coddington, Croffoot, Hilgers B, Howard A, Liebenau, McElhaney A, Rogers, and Veverka B leases.  Methane facility revenues during the first six months of 2016 and 2015 were $320,000 and $263,000, respectively.  The increase in methane facility revenues was a result of increased runtime during 2016 compared to 2015.

Comparison of the Quarters Ended June 30, 2016 and 2015

The Company reported a net loss of $1.6 million or $0.27 per share of common stock during the second quarter of 2016 compared to a net loss of $76,000 or $0.01 per share of common stock during the second quarter of 2015.  The $1.55 million increase in net loss was primarily due to a ceiling test impairment of $1.4 million recorded in the second quarter of 2016 as a result of the low oil prices experienced during 2015 and 2016, and a $617,000 decrease in revenues, partially offset by a $390,000 decrease in DD&A, a $133,000 decrease in general and administrative cost, and a $50,000 decrease in production cost and taxes.

The Company recognized $1.3 million in revenues during the second quarter of 2016 compared to $1.9 million during the second quarter of 2015. The revenue decrease from 2015 levels was primarily due to a $313,000 decrease related to a $11.33 per barrel decrease in the average oil price from an average price of $51.19 per barrel during second quarter of 2015 compared to an average price of $39.86 per barrel during the second quarter of 2016, and a $326,000 decrease related to a 6.4 MBbl decrease in sales volumes, primarily from the Albers, Croffoot, DeYoung, Howard A, Liebenau, McElhaney A, Rogers, Stahl, JR Thyfault, Veverka B and C leases.  In addition, there was a $24,000 increase in methane facility revenues related to higher runtimes and increased efficiency.

DD&A decreased $390,000 from $702,000 during the second quarter of 2015 to $312,000 during the second quarter of 2016.  This decrease was primarily due to a $262,000 decrease related to a lower oil depletion rate as a result of impairments in 2015 and 2016, and a $121,000 decrease related to a 6.4 MBbl decrease in oil sales volumes.

General and administrative costs decreased $133,000 from $418,000 during the second quarter of 2015 to $285,000 during the second quarter of 2016.  This decrease was primarily due to personnel reductions which took place during the first quarter of 2016.

Production cost and taxes decreased $50,000 from $892,000 during the second quarter of 2015 to $842,000 during the second quarter of 2016.  This decrease was primarily due to a $27,000 decrease in methane facility cost, and a $22,000 decrease in Kansas property taxes.

Comparison of the Six Months Ended June 30, 2016 and 2015

The Company reported a net loss of $3.0 million or $0.50 per share of common stock during the first six months of 2016 compared to a net loss of $591,000 or $0.10 per share of common stock during the first six months of 2015.  The $2.44 million increase in net loss was primarily due to a ceiling test impairment of $2.1 million recorded in the first six months of 2016 as a result of the low oil prices experienced during 2015 and 2016, a $1.3 million decrease in revenues, and a $380,000 tax benefit recorded during the first six months of 2015, partially offset by a $786,000 decrease in DD&A, a $413,000 decrease in production cost and taxes, and a $186,000 decrease in general and administrative cost.

The Company recognized $2.2 million in revenues during the first six months of 2016 compared to $3.5 million during the first six months of 2015. The revenue decrease from 2015 levels was primarily due to a $716,000 decrease related to a $12.90 per barrel decrease in the average oil price from an average price of $46.64 per barrel during first six months of 2015 compared to an average price of $33.75 per barrel during the first six months of 2016, and a $658,000 decrease related to a 14.1 MBbl decrease in sales volumes, primarily from the Albers, Coddington, Croffoot, Hilgers B, Howard A, Liebenau, McElhaney A, Rogers, and Veverka B leases.  In addition, there was a $57,000 increase in methane facility revenues from $263,000 during the first six months of 2015 to $320,000 during the first six months of 2016.  The increase in methane facility revenues was a result of increased runtime during 2016 compared to 2015.

 

DD&A decreased $786,000 from $1.4 million during the first six months of 2015 to $648,000 during the first six months of 2016.  This decrease was primarily due to a $505,000 decrease related to a lower oil depletion rate as a result of impairments in 2015 and 2016, and a $272,000 decrease related to a 14.1 MBbl decrease in oil sales volumes.

Production cost and taxes decreased $413,000 from $2.1 million during the first six months of 2015 to $1.7 million during the first six months of 2016.  This decrease was primarily due to a $153,000 change in oil inventory quarterly adjustment, an $83,000 decrease in methane facility cost, a $77,000 decrease in utility cost, and a $56,000 decrease in chemical cost.

General and administrative costs decreased $186,000 from $972,000 during the first six months of 2015 to $786,000 during the first six months of 2016.  This decrease was primarily due to $134,000 decrease in salaries and wages as a result of personnel reductions which took place during the first quarter of 2016, and a $41,000 reduction in legal and accounting costs.

Liquidity and Capital Resources

At June 30, 2016, the Company had a revolving credit facility with Prosperity Bank.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of June 30, 2016, the Company’s borrowing base was approximately $3.2 million, the interest rate of prime plus 0.50% per annum, and the maturity date was January 30, 2018.  The Company’s interest rate at June 30, 2016 was 4.00%.  The borrowing base is subject to an existing periodic redetermination provision in the credit facility.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  For the quarter ended December 31, 2015, the Company was in default on compliance with the Leverage Ratio covenant.  On March 28, 2016, the credit facility was amended to delete the Leverage Ratio covenant, add a Debt to Tangible Net Worth covenant, waived the default on the Interest Coverage ratio for the quarter ended December 31, 2015, waived the anticipated default for the quarter ended March 31, 2016, and waived compliance with the Interest Coverage ratio for all applicable periods through the maturity date.  Although the Company was in default of the Leverage and Interest Coverage ratios for the quarter ended December 31, 2015, the Company was in compliance at March 28, 2016 as a result of the amendment and waivers.  For the quarter ended June 30, 2016, the Company was in default on compliance with the Debt to Tangible Net Worth covenant.  On August 10, 2016, the Company received a waiver of the covenant default for the quarter ended June 30, 2016 as well as a waiver for the anticipated default for the quarter ended September 30, 2016.  Based on additional means of raising capital currently being considered by the Company, it is anticipated that the Company will be in compliance with this covenant for the quarter ended December 31, 2016.  Although the Company was in default of the Debt to Tangible Net Worth covenant for the quarter ended June 30, 2016, the Company was in compliance as of August 10, 2016 as a result of the waiver.  The next borrowing base review will take place in August 2016.

The total borrowing by the Company under the Prosperity Bank facility at June 30, 2016 and December 31, 2015 was approximately $2.3 million and $869,000, respectively.

Although the Company has not been required as of the date of this Report to make any payment of principal on the credit facility, the Company can make no assurance that in view of the conditions in the national and world economies, including the realistic possibility of low commodity prices being received for the Company’s oil and gas production for extended periods, that Prosperity Bank may not in the future make a redetermination of the Company’s borrowing base to a point below the level of current borrowings.  In such event, Prosperity Bank may require installment or other payments in such amount in order to reduce the principal of the Company’s outstanding borrowing to a level not in excess of the borrowing base as it may be redetermined.  The Company can make no assurance that it can continue normal operations indefinitely or for any specific period of time in the event of extended periods of low commodity prices, or upon the occurrence of any significant downturn or losses in operations.  In such event, the Company may be required to reduce costs of operations by various means, including not undertaking certain maintenance or reworking operations that may be necessary to keep some of the Company’s properties in production or to seek additional working capital by additional means such as issuance of equity including preferred stock or such other means as may be considered and authorized by the Company’s Board of Directors from time to time.

Net cash provided by operating activities decreased $1.5 million from $436,000 provided by operating activities during the first six months of 2015 to $1.1 million used in operating activities during the first six months of 2016.  Cash flow used in working capital was $852,000 during the first six months of 2016 compared to $82,000 used in working capital during the first six months of 2015. The $770,000 reduction in cash flow provided by working capital was primarily due to a $544,000 decrease related to a decrease in accounts payable during the first six months of 2016 as compared to an $88,000 decrease in accounts payable during the first six months of 2015.  The $1.5 million decrease in cash flow provided by operating activities was primarily due to a $770,000 decrease in cash flow provided by working capital, and a $1.3 million decrease in revenues, partially offset by a $413,000 decrease in production cost and taxes, and an $186,000 decrease in general and administrative cost.  Net cash used in investing activities was $327,000 during the first six months of 2016 compared to $444,000 used in investing activities during the first six months of 2015.  The $117,000 decrease in net cash used in investing activities was primarily a result of an $184,000 reduction in drilling, seismic, and leasehold cost during the first six months of 2016 as compared to the first six months of 2015.  Cash flow provided by financing activities during the first six months of 2016 was $1.4 million as compared to $28,000 during the first six months of 2015.  This change was primarily due additional credit facility borrowings as a result of lower oil prices and production during the first six months of 2016 as compared to the first six months of 2015.

 

Critical Accounting Policies

During the three months and six months ended June 30, 2016, there were no changes to the critical accounting policies included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

Commitments and Contingencies

The Company as designated operator was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s properties.  This action calls for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011.  In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty.   This appeal required a fully collateralized appeal bond to postpone the payment obligation until the appeal was determined.  The Company posted and collateralized this bond with RLI Insurance Company.  If the bond was not posted, the appeal would have been administratively denied and the order to the Company as operator to pay the $386,000 penalty would have become final.  On June 23, 2014, the IBLA affirmed the civil penalty without reduction.  On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans.  On July 14, 2015, the court affirmed the determination by the IBLA without reduction.  The Company determined that further appeal of the determination was not likely to reduce the penalty and the Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty affirmed on appeal and statutory interest thereon from funds borrowed under its credit facility.  The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.

During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement.  This analysis raised issues other than the “Incident of Non-Compliance” discussed previously.  The Company is discussing this analysis, as well as the civil penalty discussed previously, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis.

Cost Reduction Measures

During the quarter ended March 31, 2015, the Company initiated cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if he is still employed by the Company or still a member of the Board of Directors.  As of June 30, 2016, the reductions were approximately $162,000.  The Company has not accrued any liabilities associated with these compensation reductions.

 

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s Borrowing Base under its Credit Facility may be reduced by the lender.

The borrowing base under the Company’s revolving credit facility will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves.  If cash flow from operations or the Company’s borrowing base decreases for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected.

As a result, the Company’s ability to replace production may be limited. In addition, if the borrowing base is reduced, the Company may be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility.

 

As of June 30, 2016, the Company’s borrowing base was approximately $3.2 million of which $2.3 million had been drawn down by the Company.  The Company’s next periodic borrowing base review will take place in August 2016.

Commodity Risk

The Company's major market risk exposure is in the pricing applicable to its oil production.  Realized pricing is primarily driven by the prevailing worldwide price for crude oil.  Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.  Monthly Kansas oil prices received during the first six months of 2016 ranged from a low of $24.50 per barrel to a high of $43.02 per barrel.  As a result of the low prices experienced during 2015 and 2016, the Company recorded an impairment of its oil and gas properties during the quarter ended March 31, 2016 and the quarter ended June 30, 2016.  The Company anticipates it may need to record an additional impairment during the quarter ended September 30, 2016.

As of June 30, 2016, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At June 30, 2016, the Company had debt outstanding of $2.45 million including, as of that date, $2.3 million owed on its credit facility with Prosperity Bank. As of June 30, 2016, the interest rate on the credit facility was variable at a rate equal to prime plus 0.50% per annum.  The Company’s credit facility interest rate at June 30, 2016 was 4.00%.  The Company’s remaining debt of $133,000 has fixed interest rates ranging from 4.16% to 4.60%.

The annual impact on interest expense and the Company’s cash flows of a 10% increase in the interest rate on the credit facility would be approximately $9,000 assuming borrowed amounts under the credit facility remained at the same amount owed as of June 30, 2016.  The Company did not have any open derivative contracts relating to interest rates at June 30, 2016 or December 31, 2015.

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.

 

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

During the quarter ended December 31, 2015, the Company’s management determined that the Company’s controls over review of the quarterly ceiling test calculation were not adequate to ensure this calculation was performed correctly.  Based on this material weakness, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures, as of December 31, 2015 were not adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.  During the quarter ended March 31, 2016, the Company’s management addressed this material weakness by implementing a process to more fully analyze the impact of the Company’s tax position on its quarterly ceiling test calculation.

Changes in Internal Controls

During the quarter ended March 31, 2016, the Company implemented a process to more fully analyze the impact of the Company’s tax position on its quarterly ceiling test calculation.  Other than this process, there have been no other changes to the Company’s system of internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.  As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

PART II

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

None.

ITEM 1A.

RISK FACTORS

Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 2015 filed on March 31, 2016 which is incorporated by this reference.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.

OTHER INFORMATION

None.

 

ITEM 6.

EXHIBITS

The following exhibits are filed with this report:

 

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.

 

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