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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 September 30, 2014

 

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)

 

(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 x 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). x 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 x

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 60,842,413 common shares at November 7, 2014.

 

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TABLE OF CONTENTS

 

 

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Tengasco, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(unaudited)
(in thousands, except share data)

 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

 

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See accompanying Notes to Unaudited Condensed Consolidated Financial Statements

 

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(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 oil exploration and production is in Kansas.  The Company’s primary area of natural gas exploration and production was the Swan Creek Field in Tennessee.  On August 16, 2013 the Company closed the sale of the Swan Creek assets and the other Tennessee oil and gas related acreage.

The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”), owned and operated a 65 mile intrastate pipeline which had been constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  On August 16, 2013 the Company closed a sale of these pipeline assets.  The related results of operations were classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statement of Operations for the three and nine months ended September 30, 2013.

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 and 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 nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ended December 31, 2014. 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, 2013.

 

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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.  Prior to the sale of the Tennessee properties, natural gas meters were placed at the customer’s location and usage was billed each month.  As the natural gas properties were sold in August 2013, there were no natural gas imbalances at September 30, 2014 or December 31, 2013.  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.

Cash and Cash Equivalents

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

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.  At December 31, 2013, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash”.  On August 11, 2014, the State of Tennessee notified the holder of the Certificate of Deposit that the Company had fulfilled its obligations to the State with regard to future asset retirement obligations and therefore the Certificate of Deposit could be released.  The Company received these funds from the holder of the Certificate of Deposit in September 2014.  In addition, during the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond with RLI Insurance Company to appeal a civil penalty related to issuance of an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) concerning one of the Hoactzin properties operated by the Company pursuant to the Management Agreement (see Note 4).  At September 30, 2014 and December 31, 2013, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash” (see Note 11).

 

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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 per barrel cost which includes production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The market component is calculated using the average September 2014 and December 2013 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carried equipment and materials in inventory to be used in its Kansas operation and is 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 September 30, 2014 and December 31, 2013.  The following table sets forth information concerning the Company’s inventory (in thousands):

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 $751,000 and $736,000 at September 30, 2014 and December 31, 2013, respectively.  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.

 

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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 may not be reversed in a later period.

There was no impairment recorded at September 30, 2014 or December 31, 2013.

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 September 30, 2014 and December 31, 2013.  At September 30, 2014 and December 31, 2013, accounts receivable consisted of the following (in thousands):

 

Discontinued Operations

During 2012, the Company committed to a plan to sell its Swan Creek and Pipeline assets.  On March 1, 2013, the Company entered into an agreement to sell the Company’s Swan Creek and Pipeline assets for $1.5 million.  Closing of this transaction occurred on August 16, 2013.  The related results of the pipeline operations were classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statement of Operations for the three and nine months ended September 30, 2013.  The pipeline related cash flows were classified as “Net cash (used in) operating activities – discontinued operations”, “Net cash (used in) investing activities – discontinued operations”, and Net cash (used in) financing activities – discontinued operations”.  As the Swan Creek assets represented only a small portion of the Company’s full cost pool, these assets were classified in continuing operations for the three and nine months ended September 30, 2013.

 

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(2)	Income Taxes

The total deferred tax asset was $6.55 million and $7.3 million at September 30, 2014 and December 31, 2013, respectively.  At September 30, 2014 and December 31, 2013, the Company recorded a valuation allowance of $790,000.  Although management considers our valuation allowance as of September 30, 2014 and December 31, 2013 adequate, material changes in these amounts may occur in the future based on tax audits and changes in legislation.  The difference between the rate used to record tax expense and the statutory rate during the nine months ended September 30, 2014 is primarily related to state income tax.

(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):

 

(4)	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.

 

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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 September 30, 2014, 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 September 30, 2014 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 still the operator of record on certain of these wells.

 

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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 operator of its own properties, right-of-use and easement (“RUE”) bonds in the amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as current operator.  Hoactzin is in the process of transferring these RUE bonds from the Company to Hoactzin.  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 RUE bonds issued in the Company’s name.  The Company is not party to the indemnity agreement with Argonaut and has not provided any collateral for any of the Argonaut bonds issued.  When the transfer of the RUE’s and associated bonds is approved, the transfer of operations to Hoactzin would be complete and the Company’s involvement in the Hoactzin properties will be ended.

 

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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 September 30, 2014 and December 31, 2013 in the amount of $159,000 and $327,000, respectively.  The decrease in payables was due to payment by Hoactzin of invoices received by the Company from IndemCo related to bond premiums, which invoices have been paid by Hoactzin in full and the IndemCo bonds cancelled.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2014 and December 31, 2013 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  Since the second quarter of 2012, the only increase in the Hoactzin-related payables that have been recorded on the Company’s Consolidated Balance Sheets relate to the IndemCo bond premiums.  As all the IndemCo bonds have been cancelled, the outstanding balance of $159,000 should not increase in the future.  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 September 30, 2014 and December 31, 2013.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 and $168,000 at September 30, 2014 and December 31, 2013, respectively.

 

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 is suspending drilling payments to Hoactzin.  As of September 30, 2014, the Company has suspended approximately $570,000 in payments.  This balance of these suspended payments is recorded in the Consolidated Balance Sheet under “Accounts payable – related party”.

 

The Company has not advanced any funds to pay any obligations of Hoactzin.  No borrowing capability of the Company has been used by the Company in connection with its obligations under the Management Agreement, except for those funds used to collateralize the appeal bond with RLI Insurance Company.

 

(5)	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 $2,020,000 and $1,969,000 for the nine months ended September 30, 2014 and 2013, respectively.

 

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(6)	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 nine months ended September 30, 2014 (in thousands):

(7)	Long-Term Debt

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

At September 30, 2014, the Company had a revolving credit facility with Prosperity Bank (formerly F&M Bank & Trust Company).  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 September 30, 2014, the Company’s borrowing base was $14.3 million, the interest rate was prime plus 0.50% per annum, and the maturity date was January 27, 2016.  The Company’s interest rate at September 30, 2014 was 3.75%.  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 Methane Project and electric generation assets.  The credit facility includes certain covenants with which the Company is required to comply.  As of September 30, 2014, these covenants include leverage, interest coverage, and minimum liquidity ratios.  On September 23, 2014, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s semiannual review of the Company’s currently owned producing properties had been amended to eliminate the current ratio and General and Administrative expense covenants.  The Company is in compliance with all of the credit facility covenants.

 

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The total borrowing by the Company under the Prosperity Bank facility at September 30, 2014 and December 31, 2013 was approximately $780,000 and $3.3 million, respectively.  The next borrowing base review will take place in March 2015.

 

(8)	Methane Project

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 $122,000 and $98,000 for the nine months ended September 30, 2014 and 2013, respectively.

(9)	Discontinued Operations

The following table summarizes the pipeline related amounts included in “(Loss) from discontinued operations, net of income tax benefit” presented in the Company’s Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 (in thousands):

 

(10)	Fair Value Measurements

 

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and long term debt in our balance sheet approximates fair value as of September 30, 2014 and December 31, 2013.

 

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(11)	Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated 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 4^th 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.  While the civil penalty could ultimately be reduced in the judicial review process, as a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and an expense in its Consolidated Statements of Operations under “Production costs and taxes” for the nine months ended September 30, 2014.

 

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ITEM 2.

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

Results of Operations and Financial Condition

During the first nine months of 2014, 146 MBbl gross of oil were sold from the Company’s Kansas wells. Of the 146 MBbl, 115 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 Kansas wells during the first nine months of 2014 of 115 MBbl of oil compares to net sales of 126 MBbl of oil during the first nine months of 2013.  This 11 MBbl decrease was due primarily to decreased sales volumes from the Albers, Coddington, Harrison A, Hilgers B, Liebenau, McElhaney A, Veverka A, Veverka C, and Zerger A leases primarily due to natural declines from higher levels of production that resulted from drilling and polymers performed during 2012 and 2011.  These sales volume declines were partially offset by increased sales volumes during the first nine months of 2014 from the Hammeke and McElhaney recompletions, as well as sales from the Albers C#1, Albers B #3, Veverka D #4, and Howard A #1 wells which were completed during the first nine months of 2014.  The Company’s net revenue from the Kansas properties was $10.7 million during the first nine months of 2014 compared to $11.5 million during the first nine months of 2013.  This decrease in net revenue was due primarily to a $1.0 million decrease related to the 11 MBbl decrease in Kansas sales volumes partially offset by a $218,000 increase related to a $1.90 per barrel increase in the average Kansas oil price from $91.00 per barrel during the first nine months of 2013 to $92.90 per barrel during the first nine months of 2014.  During the first nine months of 2013, Swan Creek sales were $396,000.  No revenues were booked for Swan Creek during the first nine months of 2014 as these properties were sold in August 2013.  MMC revenues during the first nine months of 2014 and 2013 were $393,000 and $329,000, respectively.

Comparison of the Quarters Ended September 30, 2014 and 2013

The Company reported net income from continuing operations of $425,000 or $0.01 per share of common stock during the third quarter of 2014 compared to net income from continuing operations of $535,000 or $0.01 per share of common stock during the third quarter of 2013.  The $110,000 decrease in net income from continuing operations was primarily due to an $415,000 decrease in revenues, a $234,000 increase in general and administrative expenses, and an $86,000 increase in DD&A expense, partially offset by a $97,000 decrease in production cost and taxes, a $60,000 decrease in interest expense, a $29,000 increase in gain on sale of assets, and a $439,000 decrease in associated income tax expense.

 

The Company recognized $3.6 million in revenues during the third quarter of 2014 compared to $4.0 million during the third quarter of 2013. The revenue decrease from 2013 levels was primarily due to a $336,000 decrease related to a $8.70 decrease in the average Kansas oil price from an average price of $99.01 per barrel during third quarter of 2013 compared to an average price of $90.31 per barrel during the third quarter of 2014, a $99,000 decrease in Swan Creek revenues as these properties were sold in August 2013, a $33,000 decrease related to approximately a 300 Bbl decrease in Kansas sales volumes, partially offset by a $50,000 increase in methane facility revenues due to increased facility run time.

 

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General and administrative costs increased $234,000 from $461,000 during the third quarter of 2013 to $695,000 during the third quarter of 2014.  This increase was primarily related to a $161,000 increase in personnel and relocation costs, a $34,000 increase in consulting costs, and $39,000 related to subscriptions to technical geological and land software.

 

Production cost and taxes decreased $97,000 from $1.6 million during the third quarter of 2013 to $1.5 million during the third quarter of 2014.  This decrease was primarily related to a $63,000 decrease in methane facility costs, approximately $52,000 of workover costs incurred on the Schoenthaler and KU leases during the third quarter of 2013, partially offset by a $43,000 change in oil inventory.

 

Interest expense decreased $60,000 from $79,000 during the third quarter of 2013 to $19,000 during the third quarter of 2014.  This decrease in interest expense was primarily due to a $3.5 million decrease in average credit facility balance from $4.8 million during the third quarter of 2013 to $1.3 million during the third quarter of 2014.  This decrease in the average credit facility balance related to paying down the balance during the last three months of 2013 and the first nine months of 2014 as a result of operating cash flow exceeding capital spending levels.

Comparison of the Nine Months Ended September 30, 2014 and 2013

The Company reported net income from continuing operations of $1.2 million, or $0.02 per share of common stock during the first nine months of 2014 compared to net income from continuing operations of $2.3 million or $0.04 per share of common stock during the first nine months of 2013.  The $1.1 million decrease in net income from continuing operations was primarily due to a $1.1 million decrease in revenues, a $648,000 increase in production cost and taxes, and a $622,000 increase in general and administrative expense, partially offset by a $241,000 decrease in interest expense, and a $1.1 million decrease in associated income tax expense.

 

The Company recognized $11.1 million in revenues during the first nine months of 2014 compared to $12.2 million of revenues recognized during the first nine months of 2013. This $1.1 million decrease in net revenue was due primarily to a $1.0 million decrease related to the 11 MBbl decrease in Kansas sales volumes, a $396,000 reduction in Swan Creek revenues due to the sale of Swan Creek in August 2013, partially offset by a $218,000 increase related to a $1.90 per barrel increase in the average Kansas oil price from $91.00 per barrel during the first nine months of 2013 to $92.90 per barrel during the first nine months of 2014, and a $64,000 increase in methane facility revenues primarily as a result of increased facility run time.

 

Production cost and taxes increased $648,000 from $4.1 million during the first nine months of 2013 compared to $4.8 million during the first nine months of 2014.  This increase was primarily due to a one-time $386,000 expense recorded as a result of the IBLA affirmation of the civil penalty related to the 2012 Incident of Non-Compliance by the BSEE on one of Hoactzin’s properties, a $263,000 increase in Kansas well repairs and workover cost primarily as a result of work performed on the Croffoot B #6 SWD during 2014, $89,000 related to refunds of 2012 Kansas property taxes received in the second quarter 2013, partially offset by a $261,000 decrease in Swan Creek costs as these properties were sold in August 2013.

 

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General and administrative costs increased $622,000 from $1.4 million during the first nine months of 2013 compared to $2.1 million during the first nine months of 2014.  This increase was primarily related to $290,000 of costs incurred in 2014 for personnel, relocation cost, and office cost related to set up of the Denver office, a 2013 $98,000 reversal of a bad debt expense associated with the related party receivable, and $66,000 of consulting cost incurred in 2014 related to evaluating potential opportunities and review of the methane facility.

 

Interest expense decreased $241,000 from $319,000 during the first nine months of 2013 to $78,000 during the first nine months of 2014.  This decrease in interest expense was primarily due to a $5.0 million decrease in average credit facility balance from $7.1 million during the first nine months of 2013 to $2.1 million during the first nine months of 2014.  This decrease in the average credit facility balance related to paying down the balance throughout the last three months of 2013 and the first nine months of 2014 as a result of operating cash flow exceeding capital spending levels.

Liquidity and Capital Resources

At September 30, 2014, the Company had a revolving credit facility with Prosperity Bank (formerly F&M Bank & Trust Company).  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 September 30, 2014, the Company’s borrowing base was $14.3 million and the interest rate of prime plus 0.50% per annum, and the maturity date was January 27, 2016.  The Company’s interest rate at September 30, 2014 was 3.75%.  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 Methane Project and electric generation assets.  The credit facility includes certain covenants with which the Company is required to comply.  These covenants include leverage, interest coverage, and minimum liquidity ratios.  On September 23, 2014, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s semiannual review of the Company’s currently owned producing properties was amended to eliminate the current ratio and General and Administrative expense covenants.  The Company is in compliance with all of the credit facility covenants.

 

The total borrowing by the Company under the Prosperity Bank facility at September 30, 2014 and December 31, 2013 was approximately $780,000 and $3.3 million, respectively.  The next borrowing base review will take place in March 2015.

 

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.

 

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Net cash provided by operating activities from continuing operations decreased $988,000 from $6.7 million in the first nine months of 2013 to $5.7 million during the first nine months of 2014.  Cash flow provided by working capital was $1.4 million during the first nine months of 2014 compared to $326,000 provided by working capital during the first nine months of 2013. The $987,000 decrease in cash provided by operating activities was primarily due to a $1.1 million decrease in revenues, a $648,000 increase in production cost and taxes, a $622,000 increase in general and administrative expense, partially offset by the $1.1 million increase in cash provided by working capital, and a $230,000 decrease in cash interest paid.  The $1.1 million change in cash flow provided by working capital from 2013 to 2014 was primarily due to an increase in accounts payable and accrued liabilities as a result of accruing the $386,000 related to the civil penalty as well as accrual of company bonuses during 2014, a decrease in inventory, and receipt of the $120,500 of cash originally pledge as collateral for Tennessee well plugging costs.  Net cash used in investing activities from continuing operations was $3.1 million during the first nine months of 2014 compared to $731,000 used in investing activities during the first nine months of 2013.  The $2.4 million increase in net cash used in investing activities was primarily a result of a $2.0 million increase in drilling, seismic, and leasehold cost during the first nine months of 2014 as compared to the first nine months of 2013, and $274,000 in payments for electric generation equipment at the landfill during the first nine months 2014 as compared to the first nine months of 2013.  Cash flow used in financing activities from continuing operations during the first nine months of 2014 and 2013 was $2.5 million and $6.0 million, respectively.  This decrease was primarily related to lower cash flow from operating activities and increased capital spending during the first nine months of 2014 as compared to the first nine months of 2013.

 

Critical Accounting Policies

During the quarter ended September 30, 2014, 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, 2013.

Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated 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.  Tengasco believes such tests were conducted by the contractor on the facility, but the contractor failed to preserve adequate documentation.  In the 4^th 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.  The Company anticipates that the judicial review will be conducted on a relatively accelerated schedule, but can make no assurances of when the matter will be addressed or resolved by the district court.  While the civil penalty could ultimately be reduced in the judicial review process, as a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and expense in its Consolidated Statements of Operations under “Production costs and taxes” for the nine months ended September 30, 2014.  There was no liability or expense related to the $386,000 civil penalty recorded for the nine months ended September 30, 2013.  In the event any portion of the civil penalty is affirmed, the Company expects to seek reimbursement of such penalty from Hoactzin, pursuant to the terms of the Management Agreement.  However, there can be no assurances that the Company would be successful in such a claim.

 

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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.

 

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As of September 30, 2014, the Company’s borrowing base was set at $14.3 million of which $780,000 million had been drawn down by the Company.  The Company’s next periodic borrowing base review will occur in March 2015.

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.  Although not as volatile as in previous years, monthly Kansas oil prices received during the first nine months of 2014 ranged from a low of $86.51 per barrel to a high of $98.51 per barrel.

As of September 30, 2014, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At September 30, 2014, the Company had debt outstanding of $929,000 including, as of that date, $780,000 owed on its credit facility with Prosperity Bank. As of September 30, 2014, 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 September 30, 2014 was 3.75%.  The Company’s remaining debt of $149,000 has fixed interest rates ranging from 5.5% to 8.25%.

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 $2,900 assuming borrowed amounts under the credit facility remained at the same amount owed as of September 30, 2014.  The Company did not have any open derivative contracts relating to interest rates at September 30, 2014 or December 31, 2013.

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.

 

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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, and other members of management have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and 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.

Changes in Internal Controls

During the period covered by this Report, there have been no 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, 2013 filed on March 31, 2014 which is incorporated by this reference.

 

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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:

31.1

Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a.

32.1

Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Calculation Linkbase Document

101.DEF

XBRL Taxonomy Definition Linkbase Document

101.LAB

XBRL Taxonomy Label Linkbase Document

101.PRE

XBRLTaxonomy Presentation Linkbase Document

 

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SIGNATURES

 

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

 

 

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