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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, 2017

Commission File No. 1-15555

(Exact name of registrant as specified in its charter)

 

8000 E. Maplewood Ave, Suite 130, 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, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth 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: 10,614,523 common shares at August 7, 2017.

 

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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.

 

 

(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, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  The Company sold all its pipeline assets on August 16, 2013.

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operates treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of June 30, 2017 and June 30, 2016 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.  The condensed consolidated balance sheet as of December 31, 2016 is derived from the audited financial statements, but does not include all disclosures required by U.S. GAAP.  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 three months and six months ended June 30, 2017 are not necessarily indicative of the results that may be expected for the year ended December 31, 2017. 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, 2016.

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 condensed consolidated financial statements are prepared in conformity with U.S. GAAP which require 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 impairments 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 various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the condensed 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 gas, 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 material natural gas imbalances at June 30, 2017 or December 31, 2016.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes.  No methane gas was sold during the three months and six months ended June 30, 2017 or 2016.

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 net realizable value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended June 30, 2017 and December 31, 2016.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The net realizable value component is calculated using the average June 2017 and December 2016 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 net realizable value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The net realizable value component is based on estimated sales value for similar equipment and materials as of June 30, 2017 and December 31, 2016.  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 $48,000 and $106,000 at June 30, 2017 and December 31, 2016, 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.

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, but recorded no impairment for the three months or six months ended June 30, 2017.

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 sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first 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, 2017 and December 31, 2016.

 

 

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

Reclassifications

Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income.

(2)

Liquidity

During 2016, the Company incurred a net loss of approximately $4.2 million.  In addition as of December 31, 2016, as discussed in Note 10 Long-Term Debt, the Company was in default with various covenants included in its credit facility with Prosperity Bank.  Each of these defaults was cured either through a waiver or an amendment to its credit facility.  Through August 2018, the Company believes its revenues will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $1.25 million borrowing base with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

(3)	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.

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 2017 as a result of $26.4 million of net operating loss carry forwards that existed at December 31, 2016.  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, 2017, the Company has recorded a full valuation allowance on its deferred tax assets primarily due to cumulated losses incurred during the 3 years ended December 31, 2016.  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, 2017.

(4)	Capital Stock

 

Common Stock

On January 4, 2017, 5,264 common shares were issued in the aggregate to the Company’s four directors and CFO and interim CEO.

On February 13, 2017, 4,498,698 common shares were issued to participants of the Company’s rights offering which closed on February 2, 2017.  Of the 4,498,698 common shares issued, 3,293,407 were issued to the Company’s directors, management, and affiliates.  The Company received approximately $2.7 million in gross proceeds from this rights offering.  The direct costs associated with this rights offering were approximately $242,000.

 

 

On April 3, 2017, 7,267 common shares were issued in the aggregate to the Company’s four directors and CFO and interim CEO.

On July 3, 2017, 5,571 common shares were issued in the aggregate to the Company’s four directors and CFO and interim CEO.

Rights Agreement

Effective March 17, 2017 the Board of Directors declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock, $0.001 par value per share (“Common Stock”). The dividend was paid to the stockholders of record at the close of business on March 27, 2017 (the “Record Date”). Each Right entitles the registered holder, subject to the terms of the Rights Agreement dated as of March 16, 2017 (the “Rights Agreement”) between the Company and the Rights Agent, Continental Stock Transfer & Trust Company, to purchase from the Company one one-thousandth of a share of the Company’s Series A Preferred Stock at a price of $1.10 (the “Exercise Price”), subject to certain adjustments.

The purpose of the Rights Agreement is to reduce the risk that the Company’s ability to use its net operating losses to reduce potential future federal income tax obligations would be limited by reason of the Company’s experiencing an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock.

The Rights will not be exercisable until the “Distribution Date”, which is generally defined as the earlier to occur of:(i) a public announcement or filing that a person or group has, become an “Acquiring Person” which is defined as a person or group of affiliated or associated persons or persons acting in concert who, at any time after the date of the Rights Agreement, have acquired, or obtained the right to acquire, beneficial ownership of 4.95% or more of the Company’s outstanding shares of Common Stock; or a person or group currently owning 4.95% (or more) of the Company’s outstanding shares acquires additional shares of the Company’s stock; subject to certain exceptions; or (ii) the commencement of, or announcement of an intention to commence, a tender offer or exchange offer the consummation of which would result in any person becoming an Acquiring Person.

The Rights will expire prior to the earliest of March 16, 2020; the close of business on the first day after the Company’s 2017 annual meeting of stockholders, if approval by the stockholders of the Company of the Rights Agreement has not been obtained at such meeting; a date the Board of Directors determines by resolution in its business judgment that the Agreement is no longer necessary or appropriate; or in certain other specified circumstances.

At any time after any person or group of affiliated or associated persons becomes an Acquiring Person, the Board, at its option, may exchange each Right (other than Rights owned by such person or group of affiliated or associated persons which will have become void), in whole or in part, at an exchange ratio of two shares of Common Stock per outstanding Right (subject to adjustment).

For further information on the Rights Agreement, please refer to the Rights Agreement that was attached in full as an exhibit to the Company’s Form 8-K filed with SEC on March 17, 2017.

Preferred Stock

Series A Preferred Stock has a par value of $0.001 and 10,000 shares have been designated.  No shares of Series A Preferred Stock have been issued by the Company pursuant to the Rights Agreement described above or otherwise.

(5)	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):

 

 

For the six months ended June 30, 2016, 229 shares were excluded from dilutive shares as they would have been anti-dilutive.

(6)	Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09 Revenue from Contracts with Customers (“ASU 2014-09”). This ASU, as amended, superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to implement ASU 2014-09 as of January 1, 2018 and are currently in the process of evaluating the impact of the new standard on our accounting policies, processes, system requirements and financial reporting.  Based on the evaluation performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account previously identified, and we do not expect any change related to the allocation of the transaction price and the timing of our revenue to have a material impact on our consolidated financial statements or results of operations.  We will continue to assess the impact of adopting this ASU.

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 August 2016, the FASB issued Update 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.  This amendment provides guidance on certain cash flow classification issues, thereby reducing the current and potential future diversity in practice. This guidance is effective for annual periods beginning after December 15, 2017, 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.

 

(7)	Related Party Transactions

On September 17, 2007, Hoactzin Partners, L.P. (“Hoactzin”) subscribed to a drilling program offered by the Company consisting of wells to be drilled on the Company’s Kansas Properties (the “Program”).  Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin and of Dolphin Offshore Partners, L.P., the Company’s largest shareholder.  Hoactzin was also conveyed a net profits interest in the MMC facility at the Carter Valley municipal solid waste landfill owned and operated by Republic Services, Inc. in Church Hill, Tennessee where the Company installed a propriety combination of advanced gas treatment technology to extract the methane component of the purchased gas stream (the “Methane Project”).  The net profits interest owned by Hoactzin is now 7.5% of the net profits as defined by agreement and takes into account specific costs and expenses as well as gross gas revenues for the project.  As a result of the startup costs, monthly operating expenses, and gas production levels experienced, no net profits as defined were realized during the period from the project startup in April, 2009 through June 30, 2017 for payment to Hoactzin under the net profits interest.  Since the start of 2014, there have been no methane gas sales or revenues, and consequently no net profits attributable to Hoactzin’s net profits interest.

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, and offshore Texas and offshore Louisiana. 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 expired on December 18, 2012.

The Company entered into a transition agreement with Hoactzin whereby the Company no longer performs operations, but administratively assists Hoactzin in becoming operator of record of these wells and transferring all bonds from the Company to Hoactzin.  This assistance is primarily related to signing the necessary documents to effectuate this transition.  Hoactzin and its controlling member are indemnifying 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.  As of the date of this Report, the Company continues to administratively assist Hoactzin with this transition process.

During the term of the Management Agreement, the Company became the operator of certain properties owned by Hoactzin.  The Company obtained over time, bonds for the purpose of covering substantial plugging and abandonment obligations and Rights-of-Use and Easements (“RUE’s) on Hoactzin’s properties located in federal offshore waters in favor of the Bureau of Safety and Environmental Enforcement (“BSEE”).  As of May 15, 2014, all such operator bonds related to plugging and abandonment obligations as to the Company were released by the BSEE and were cancelled by the issuer of the bonds.  As of December 31, 2016, the transfer of all RUE’s and associated bonds and the transfer of operations to Hoactzin was completed. Accordingly, the exposure to the Company under any bonds or any indemnity agreements relating to any bond has decreased to zero.

As operator during the term of the Management Agreement that expired in 2012, 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.  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, 2017 and December 31, 2016 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of June 30, 2017 and December 31, 2016 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  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 record an allowance in the amount of $159,000 for the balances outstanding at June 30, 2017 and December 31, 2016.  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 at June 30, 2017 and December 31, 2016.

 

(8)	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 $414,000 and $583,000 for the six months ended June 30, 2017 and 2016, respectively.  During the six months ended June 30, 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $2,000 gain on asset retirement obligations.  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, but recorded no impairment for the six months ended June 30, 2017.  As a result of the ceiling test impairments during 2015 and the first three quarters of 2016, the accumulated depreciation, depletion, and amortization was netted against the cost to reflect the post impairment value of the oil and gas properties.  As no ceiling test impairment was recorded during the quarters ended December 31, 2016 and March 31, 2107 and June 30, 2017, this amount was not netted against cost, but remained in accumulated depreciation, depletion, and amortization at December 31, 2016 and June 30, 2017.

(9)	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, 2017 (in thousands):

(10)	Long-Term Debt

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

 

The presentation of unamortized debt issuance cost has been reclassified from a reduction of long term debt to a non-current asset.  This reclassification was based on Securities and Exchange Commission staff guidance as there was an absence of authoritative guidance with update 2015-03 for debt issuance costs related to line-of-credit arrangements.  Unamortized debt issuance cost at December 31, 2016 that was reclassified to a non-current asset was approximately $24,000.

 

 

At June 30, 2017, the Company had a revolving credit facility with Prosperity Bank. This is the Company’s primary source to fund working capital and future capital spending. 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, 2017, the Company’s borrowing base was $1.25 million. 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. At June 30, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio. During the quarter ended June 30, 2017, the Company was in compliance with all covenants.

Effective March 16, 2017, 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 and restated to among other things, decrease the Company’s borrowing base from $3.0 million to approximately $1.25 million, and extend the term of the facility to July 31, 2018.  In addition, all the covenants were removed and replaced with the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA Ratio < 3.5x; and (c) Interest Coverage Ratio > 3.0x.  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 4.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million and the Company had no outstanding borrowing under the facility as of June 30, 2017.  The next borrowing base review will take place in August 2017.

For the quarter ended December 31, 2016, the Company was in default on compliance with the minimum liquidity ratio.  On March 16, 2017, the Company received a waiver from Prosperity Bank.  Although the Company was in default of the minimum liquidity covenant for the quarter ended December 31, 2016, the Company was in compliance as a result of the waiver.  In addition, the Company also received a waiver from Prosperity Bank for an anticipated default on the debt to equity covenant.  Had the Company not received this waiver, it would have been in default on the debt to equity covenant for the quarter ended December 31, 2016.

The proceeds received from the Company’s rights offering which closed on February 2, 2017, were used primarily to pay off the Company’s credit facility.  The Company was able to record the credit facility balance as of December 31, 2016 as a non-current liability since the Company had the ability and the intent to repay this debt using proceeds from the rights offering. (See Note 4. Capital Stock)

(11)	Manufactured Methane

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

The Manufactured Methane facilities were placed into service on April 1, 2009.  The Manufactured Methane facilities are being depreciated over a remaining estimated useful life of approximately 25 years based on estimated landfill closure date of December 2041.  The Company recorded depreciation expense of $31,000 and $30,000 for the six months ended June 30, 2017 and 2016, respectively.

(12)	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, 2017 and December 31, 2016.

(13)	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 called 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.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction.  The Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility.  In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.  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, 2017, 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 is still employed by the Company or still a member of the Board of Directors.  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 2017, 67.0 MBbl gross of oil were sold from the Company’s properties.  Of the 67.0 MBbl sold, 52.3 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 2017 of 52.3 MBbl of oil compares to net sales of 55.5 MBbl of oil during the first six months of 2016.  The Company’s net revenue from its oil and gas properties was $2.3 million during the first six months of 2017 compared to $1.9 million during the first six months of 2016.  This increase in net revenue was primarily due to a $566,000 increase related to an $10.80 per barrel increase in the average oil price from $33.75 per barrel during the first six months of 2016 to $44.55 per barrel during the first six months of 2017, partially offset by a $106,000 decrease related to a 3.2 MBbl decrease in sales volumes.  The 3.2 MBbl decrease was primarily due to decreased sales volumes from the Albers A, Albers B, Ben Tempero, Croffoot, Howard A, Lewis, Liebenau, Schneller, and Veverka A leases.  Methane facility revenues during the first six months of 2017 and 2016 were $315,000 and $320,000, respectively.

Comparison of the Quarters Ended June 30, 2017 and 2016

The Company reported a net loss of $178,000 or $0.02 per share of common stock during the second quarter of 2017 compared to a net loss of $1.6 million or $0.27 per share of common stock during the second quarter of 2016.  The $1.4 million decrease 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, a $36,000 increase in revenues, a $27,000 decrease in general and administrative costs, a $70,000 decrease in DD&A, and a $22,000 decrease in interest expense, partially offset by a $150,000 increase in production cost and taxes.

The Company recognized $1.318 million in revenues during the second quarter of 2017 compared to $1.282 million during the second quarter of 2016. The $36,000 revenue increase from 2016 levels was primarily due to a $78,000 increase related to a $2.96 per barrel increase in the average oil price from an average price of $39.86 per barrel during second quarter of 2016 compared to an average price of $42.82 per barrel during the second quarter of 2017, partially offset by a $51,000 decrease related to a 1.3 MBbl decrease in sales volumes, primarily from the Albers B, Howard A, Lewis, Liebenau, and Schneller leases.  In addition, there was a $10,000 increase in methane facility revenues.

General and administrative costs decreased $27,000 from $285,000 during the second quarter of 2016 to $258,000 during the second quarter of 2017.  This decrease was primarily due to a $39,000 reduction in legal and accounting cost.

DD&A decreased $70,000 from $312,000 during the second quarter of 2016 to $242,000 during the second quarter of 2017.  This decrease was primarily due to a $56,000 decrease related to a lower oil depletion rate as a result of impairments in 2016, and a $15,000 decrease related to the decrease in oil sales volumes.

Interest expense decreased $22,000 from $26,000 during the second quarter of 2016 to $4,000 during the second quarter of 2017.  This decrease was primarily related to paying off the credit facility during the first quarter of 2017.  The credit facility was paid off using proceeds from the rights offering which closed in February 2017.

Production costs and taxes and methane facility costs increased $150,000 from $842,000 during the second quarter of 2016 to $992,000 during the second quarter of 2017.  This increase was primarily due to a $179,000 change in the oil inventory quarterly adjustment, and a $40,000 increase in methane facility costs, partially offset by a $57,000 decrease in tank battery and lease road repair costs.

Comparison of the Six Months Ended June 30, 2017 and 2016

The Company reported a net loss of $391,000 or $0.04 per share of common stock during the first six months of 2017 compared to a net loss of $3.0 million or $0.50 per share of common stock during the first six months of 2016.  The $2.6 million decrease 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 $447,000 increase in revenues, a $194,000 decrease in general and administrative costs, and a $169,000 decrease in DD&A, partially offset by a $281,000 increase in production cost and taxes.

The Company recognized $2.7 million in revenues during the first six months of 2017 compared to $2.2 million during the first six months of 2016. The revenue increase from 2016 levels was primarily due to a $566,000 increase related to a $10.80 per barrel increase in the average oil price from an average price of $33.75 per barrel during the first six months of 2016 compared to an average price of $44.55 per barrel during the first six months of 2017, partially offset by a $106,000 decrease related to 3.2 MBbl decrease in sales volumes, primarily from the Albers A, Albers B, Ben Tempero, Croffoot, Howard A, Lewis, Liebenau, Schneller, and Veverka A leases.  In addition, there was a $5,000 decrease in methane facility revenues.

 

General and administrative costs decreased $194,000 from $786,000 during the first six months of 2016 to $592,000 during the first six months of 2017.  This decrease was primarily due to an $112,000 decrease in corporate payroll costs as a result of personnel reductions during the first quarter 2016, and a $56,000 reduction in legal and accounting cost.

DD&A decreased $169,000 from $648,000 during the first six months of 2016 to $479,000 during the first six months of 2017.  This decrease was primarily due to a $136,000 decrease related to a lower oil depletion rate as a result of impairments in 2016, and a $33,000 decrease related to the decrease in oil sales volumes.

Production costs and taxes and methane facility costs increased $281,000 from $1.7 million during the first six months of 2016 to $2.0 million during the first six months of 2017.  This increase was primarily due to a $248,000 change in the oil inventory adjustment, and a $145,000 increase in methane facility costs, partially offset by a $59,000 decrease in tank battery and lease road repair costs, and a $36,000 decrease in Kansas property tax costs.

Liquidity and Capital Resources

At June 30, 2017, the Company had a revolving credit facility with Prosperity Bank.  This is the Company’s primary source to fund working capital and future capital spending.  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, 2017, the Company’s borrowing base was $1.25 million.  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.  At June 30, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio.  During the quarter ended June 30, 2017, the Company was in compliance with all covenants.

Effective March 16, 2017, 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 and restated to among other things, decrease the Company’s borrowing base from $3.0 million to approximately $1.25 million, and extend the term of the facility to July 31, 2018.  In addition, all the covenants were removed and replaced with the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA Ratio < 3.5x; and (c) Interest Coverage Ratio > 3.0x.  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 4.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million and the Company had no outstanding borrowing under the facility as of June 30, 2017.

For the quarter ended December 31, 2016, the Company was in default on compliance with the minimum liquidity ratio.  On March 16, 2017, the Company received a waiver from Prosperity Bank.  Although the Company was in default of the minimum liquidity covenant for the quarter ended December 31, 2016, the Company was in compliance as a result of the waiver.  In addition, the Company also received a waiver from Prosperity Bank for an anticipated default on the debt to equity covenant.  Had the Company not received this waiver, it would have been in default on the debt to equity covenant for the quarter ended December 31, 2016.  In February 2017, the Company paid off the credit facility using proceeds from the Company’s rights offering which closed on February 2, 2017.  The Company was able to record the credit facility balance as of December 31, 2016 as a non-current liability since the Company had the ability and the intent to repay this debt using proceeds from the rights offering.

The total borrowing by the Company under the facility at June 30, 2017 and December 31, 2016 was $0 and $2.4 million, respectively.  As disclosed in previous Company filings, on February 13, 2017, 4,498,698 common shares were issued to participants of the Company’s rights offering which closed on February 2, 2017.  Of the 4,498,698 common shares issued, 3,293,407 were issued to the Company’s directors, management, and affiliates.  The Company received approximately $2.7 million in proceed from this offering.  The proceeds were used primarily to pay off the Company’s credit facility.  The next borrowing base review will take place in August 2017.

During 2016, the Company incurred a net loss of approximately $4.2 million.  In addition as of December 31, 2016, the Company was in default with various covenants included in its credit facility with Prosperity Bank.  Each of these defaults was cured either through a waiver or an amendment to its credit facility.  Through August 2018, the Company believes its revenues will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $1.25 million borrowing base with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

 

Net cash provided by operating activities increased $1.1 million from $1.1 million used in operating activities during the first six months of 2016 to $21,000 provided by operating activities during the first six months of 2017.  Cash flow used in working capital was $152,000 during the first six months of 2017 compared to $852,000 used in working capital during the first six months of 2016. The $700,000 reduction in cash flow used in working capital was primarily due to a $634,000 payment of suspended Hoactzin drilling program payments that was paid in January 2016.  The $1.1 million increase in cash flow provided by operating activities was primarily due to a $700,000 decrease in cash flow used in working capital, a $447,000 increase in revenues, and a $194,000 decrease in general and administrative costs, partially offset by a $281,000 increase in production costs and taxes and methane facility costs.  Net cash used in investing activities was $134,000 during the first six months of 2017 compared to $327,000 used in investing activities during the first six months of 2016.  The $193,000 decrease in net cash used in investing activities was primarily a result of a $151,000 reduction in drilling, seismic, and leasehold cost during the first six months of 2017 compared to the first six months of 2016.  Cash flow provided by financing activities during the first six months of 2017 was $169,000 compared to $1.4 million provided by financing activities during the first six months of 2016.  During the first six months of 2017, the Company raised $2.7 million in proceeds as a result of a rights offering which closed on February 2, 2017.  The direct costs associated with this rights offering were approximately $242,000, of which $140,000 was incurred during 2016.  The net proceeds from this offering were used primarily to pay off the Company’s credit facility.

Critical Accounting Policies

During the six months ended June 30, 2017, 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, 2016.

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 called 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.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction.  The Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility.  In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.  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, 2017, 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 is still employed by the Company or still a member of the Board of Directors.  For the period January 1, 2015 through June 30, 2017, the reductions were approximately $325,000.  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 naturally declining 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, 2017, the Company’s borrowing base was approximately $1.25 million of which zero had been drawn down by the Company.  The Company’s next periodic borrowing base review will take place in August 2017.

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.  The average monthly Kansas oil prices received during the first six months of 2017 ranged from a low of $39.82 per barrel to a high of $47.49 per barrel.

As of June 30, 2017, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At June 30, 2017, the Company had debt outstanding of approximately $98,000, none of which was owed on its credit facility with Prosperity Bank. As of June 30, 2017, 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, 2017 was 4.75%.  The Company’s remaining debt of $98,000 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 zero assuming borrowed amounts under the credit facility remained at the same amount owed as of June 30, 2017.  The Company did not have any open derivative contracts relating to interest rates at June 30, 2017 or December 31, 2016.

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.

Changes in Internal Controls

During the six months ended June 30, 2017, 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

The Company has been named as a defendant in a breach of contract lawsuit titled Offshore Oilfield Services, Inc. v. Prime 8 Offshore, LLC and Tengasco, Inc., No 201657156 in the 270^th District Court of Harris County, Texas (the “Litigation”) filed in October 2016.  Tengasco, Inc. was served by mail postmarked January 6, 2017.  Defendant Prime8 Offshore, LLC (“Prime8”) was previously served.

 

The Litigation seeks recovery of approximately $188,000 in unpaid material and labor costs (plus plaintiff’s attorney’s fees and interest) for offshore operations contracted by Prime8 to be performed by the plaintiff Offshore Oildfield Services, Inc. (“Offshore Oilfield”) upon several properties owned by Hoactzin Partners, LP (“Hoactzin”) in the Gulf of Mexico under a master services agreement  signed between Prime8 and Offshore Oilfield in May 2014 (“MSA”).  Offshore Oilfield alleges breach of the MSA by Prime8 and Tengasco for failure to pay for materials provided or services performed in 2014 and 2015.  Tengasco did not sign the MSA and had no knowledge of it or any other such agreement utilized in operation by Hoactzin, Prime8, or any subcontractor concerning Hoactzin’s Gulf properties.  No allegation is made in the Litigation that Tengasco specifically directed or was otherwise involved in the performance of the services rendered or materials provided or failure to pay for same.  Hoactzin, as opposed to Tengasco, directed Prime8 in the conduct of all matters described in the Litigation and either paid or failed to pay any and all charges for services and materials for which Prime8 had contracted with subcontractors such as Offshore Oilfield to be provided at all of Hoactzin’s properties in the Gulf owned and physically operated exclusively by Hoactzin.

The Litigation concerns events occurring during the period covered by that certain Transition Agreement between Hoactzin and Tengasco made effective December 18, 2012.  Pursuant to part 5 of that agreement, Hoactzin is made subject to certain indemnity obligations to Tengasco.

Hoactzin has also specifically agreed in writing to protect, defend, indemnify, and hold harmless Tengasco from and against any and all claims, demands, and causes of action made or awarded against Tengasco in the Litigation and to pay in the first instance all related losses, damages, costs and expenses relating to the Litigation including damages and plaintiff’s attorney’s fees awarded, and all litigation expenses incurred, the Company’s currently billed attorneys’ fees and court costs, relating to or arising out of Tengasco’s  status as a defendant in the Litigation.  Hoactzin has also agreed that counsel currently representing Prime8 may also represent Tengasco in the Litigation as the positions of Tengasco and Prime8 appear to be aligned for purposes of the Litigation.

The case is currently set for trial in October 2017 but the setting may be continued to a later date.

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, 2016 filed on March 30, 2017 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.

Dated:  August 14, 2017

TENGASCO, INC.

 

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