Document And Entity Information
v3.7.0.1
Document And Entity Information - shares
3 Months Ended
Mar. 31, 2017
May 08, 2017
Document And Entity Information [Abstract]    
Document Type 10-Q  
Amendment Flag false  
Document Period End Date Mar. 31, 2017  
Document Fiscal Year Focus 2017  
Document Fiscal Period Focus Q1  
Entity Registrant Name TENGASCO INC  
Entity Central Index Key 0001001614  
Current Fiscal Year End Date --12-31  
Entity Filer Category Smaller Reporting Company  
Entity Common Stock, Shares Outstanding   10,608,952

Condensed Consolidated Balance Sheets
v3.7.0.1
Condensed Consolidated Balance Sheets - USD ($)
$ in Thousands
Mar. 31, 2017
Dec. 31, 2016
Current    
Cash and cash equivalents $ 228 $ 76
Accounts receivable, less allowance for doubtful accounts of $14 536 490
Accounts receivable - related party, less allowance for doubtful accounts of $159
Inventory 597 627
Other current assets 255 421
Total current assets 1,616 1,614
Loan fees, net 20 24
Oil and gas properties, net (full cost accounting method) 5,020 5,225
Manufactured Methane facilities, net 1,544 1,559
Other property and equipment, net 123 140
Total assets 8,323 8,562
Current liabilities    
Accounts payable - trade 199 303
Accounts payable - other 159 159
Accrued and other current liabilities 216 274
Current maturities of long-term debt 53 55
Total current liabilities 627 791
Asset retirement obligation 2,071 2,046
Long term debt, less current maturities 34 2,447
Total liabilities 2,732 5,284
Commitments and contingencies (Note 13)
Preferred stock, 25,000,000 shares authorized    
Series A Preferred stock, $0.001 par value, 10,000 shares designated; 0 shares issued and outstanding
Common stock, $.001 par value, authorized 100,000,000 shares, 10,601,685 and 6,097,723 shares issued and outstanding 11 6
Additional paid-in capital 58,308 55,787
Accumulated deficit (52,728) (52,515)
Total stockholders' equity 5,591 3,278
Total liabilities and stockholders' equity $ 8,323 $ 8,562

Condensed Consolidated Balance Sheets (Parenthetical)
v3.7.0.1
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Thousands
Mar. 31, 2017
Dec. 31, 2016
Allowance for doubtful accounts $ 14 $ 14
Preferred stock, shares authorized 25,000,000 25,000,000
Common stock, par value $ 0.001 $ 0.001
Common stock, shares authorized 100,000,000 100,000,000
Common stock, shares issued 10,601,685 6,097,723
Common stock, shares outstanding 10,601,685 6,097,723
Related Party [Member]    
Allowance for doubtful accounts $ 159 $ 159
Series A Preferred Stock [Member]    
Preferred stock, par value $ 0.001 $ 0.001
Preferred stock, shares authorized 10,000 10,000
Preferred stock, shares issued 0 0
Preferred stock, shares outstanding 0 0

Condensed Consolidated Statements Of Operations
v3.7.0.1
Condensed Consolidated Statements Of Operations - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Revenues    
Oil and gas properties $ 1,209,000 $ 782,000
Methane facility 135,000 150,000
Total revenues 1,344,000 932,000
Cost and expenses    
Production costs and taxes 971,000 839,000
Depreciation, depletion, and amortization 236,000 336,000
General and administrative 334,000 500,000
Impairment 0 641,000
Total cost and expenses 1,541,000 2,316,000
Net loss from operations (197,000) (1,384,000)
Other expense    
Interest expense (16,000) (20,000)
Total other expenses (16,000) (20,000)
Loss from operations before income tax (213,000) (1,404,000)
Deferred income tax benefit
Net loss $ (213,000) $ (1,404,000)
Net loss per share    
Basic and fully diluted $ (0.03) $ (0.23)
Shares used in computing earnings per share    
Basic and fully diluted 8,452,132 6,084,241

Condensed Consolidated Statements Of Cash Flows
v3.7.0.1
Condensed Consolidated Statements Of Cash Flows - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Operating activities    
Net loss from operations $ (213,000) $ (1,404,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:    
Depreciation, depletion, and amortization 236,000 336,000
Amortization of loan fees-interest expense 4,000 1,000
Accretion on asset retirement obligation 36,000 36,000
Impairment 0 641,000
Stock based compensation 4,000 2,000
Changes in assets and liabilities:    
Accounts receivable (46,000) (64,000)
Inventory and other assets 56,000 11,000
Accounts payable (104,000) (574,000)
Accrued and other current liabilities (51,000) (42,000)
Settlement on asset retirement obligation (10,000) (14,000)
Net cash used in operating activities (88,000) (1,071,000)
Investing activities    
Additions to oil and gas properties (7,000) (259,000)
Additions to methane project   (36,000)
Additions to other property and equipment   (6,000)
Net cash used in investing activities (7,000) (301,000)
Financing activities    
Repayments of borrowings (2,815,000) (491,000)
Proceeds from borrowings 400,000 1,850,000
Proceeds from stock issuance in rights offering 2,699,000  
Costs of stock issuance in rights offering (37,000)  
Net cash provided by financing activities 247,000 1,359,000
Net change in cash and cash equivalents 152,000 (13,000)
Cash and cash equivalents, beginning of period 76,000 40,000
Cash and cash equivalents, end of period 228,000 27,000
Supplemental cash flow information:    
Cash interest payments 12,000 19,000
Supplemental non-cash investing and financing activities:    
Financed company vehicles   $ 23,000
Costs of stock issuance in rights offering $ (140,000)  

Description Of Business And Significant Accounting Policies
v3.7.0.1
Description Of Business And Significant Accounting Policies
3 Months Ended
Mar. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]  
Description Of Business And Significant Accounting Policies

(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 March 31, 2017 and March 31, 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 ended March 31, 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 March 31, 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 ended March 31, 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 March 31, 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 March 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 March 31, 2017 and December 31, 2016.  The following table sets forth information concerning the Company’s inventory (in thousands):







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Oil – carried at net realizable value

 

$

475 

 

$

505 

Equipment and materials – carried at net realizable value

 

 

122 

 

 

122 

Total inventory

 

$

597 

 

$

627 



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 March 31, 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 ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 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 March 31, 2017 and December 31, 2016.



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







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Revenue

 

$

512 

 

$

476 

Joint interest

 

 

22 

 

 

21 

Other

 

 

16 

 

 

Allowance for doubtful accounts

 

 

(14)

 

 

(14)

Total accounts receivable

 

$

536 

 

$

490 

 



Reclassifications



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


Description Of Business And Significant Accounting Policies (Policy)
v3.7.0.1
Description Of Business And Significant Accounting Policies (Policy)
3 Months Ended
Mar. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]  
Basis Of Presentation

Basis of Presentation



The accompanying unaudited condensed consolidated financial statements as of March 31, 2017 and March 31, 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 ended March 31, 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

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

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

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 March 31, 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 ended March 31, 2017 or 2016.

Cash And Cash Equivalents

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



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 March 31, 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 March 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 March 31, 2017 and December 31, 2016.  The following table sets forth information concerning the Company’s inventory (in thousands):







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Oil – carried at net realizable value

 

$

475 

 

$

505 

Equipment and materials – carried at net realizable value

 

 

122 

 

 

122 

Total inventory

 

$

597 

 

$

627 



Full Cost Method Of Accounting

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 March 31, 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 ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.

Accounts Receivable

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 March 31, 2017 and December 31, 2016.



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







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Revenue

 

$

512 

 

$

476 

Joint interest

 

 

22 

 

 

21 

Other

 

 

16 

 

 

Allowance for doubtful accounts

 

 

(14)

 

 

(14)

Total accounts receivable

 

$

536 

 

$

490 

 



Reclassifications

Reclassifications



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


Description Of Business And Significant Accounting Policies (Tables)
v3.7.0.1
Description Of Business And Significant Accounting Policies (Tables)
3 Months Ended
Mar. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]  
Inventory



 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Oil – carried at net realizable value

 

$

475 

 

$

505 

Equipment and materials – carried at net realizable value

 

 

122 

 

 

122 

Total inventory

 

$

597 

 

$

627 



Accounts Receivable



 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Revenue

 

$

512 

 

$

476 

Joint interest

 

 

22 

 

 

21 

Other

 

 

16 

 

 

Allowance for doubtful accounts

 

 

(14)

 

 

(14)

Total accounts receivable

 

$

536 

 

$

490 




Description Of Business And Significant Accounting Policies (Narrative) (Details)
v3.7.0.1
Description Of Business And Significant Accounting Policies (Narrative) (Details) - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Description Of Business And Significant Accounting Policies [Abstract]      
Methane gas revenue $ 0 $ 0  
Unevaluated properties $ 48,000   $ 106,000
Current cost discount 10.00%    
Impairment $ 0 $ 641,000  

Description Of Business And Significant Accounting Policies (Inventory) (Details)
v3.7.0.1
Description Of Business And Significant Accounting Policies (Inventory) (Details) - USD ($)
$ in Thousands
Mar. 31, 2017
Dec. 31, 2016
Description Of Business And Significant Accounting Policies [Abstract]    
Oil - carried at net realizable value $ 475 $ 505
Equipment and materials - carried at net realizable value 122 122
Total inventory $ 597 $ 627

Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details)
v3.7.0.1
Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details) - USD ($)
$ in Thousands
Mar. 31, 2017
Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Allowance for doubtful accounts $ (14) $ (14)
Total accounts receivable 536 490
Revenue [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts receivable 512 476
Joint Interest [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts receivable 22 21
Other [Member]    
Accounts, Notes, Loans and Financing Receivable [Line Items]    
Accounts receivable $ 16 $ 7

Liquidity
v3.7.0.1
Liquidity
3 Months Ended
Mar. 31, 2017
Liquidity [Abstract]  
Liquidity

(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 8 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.  During 2017, 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.


Liquidity (Narrative) (Details)
v3.7.0.1
Liquidity (Narrative) (Details) - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Mar. 16, 2017
Mar. 15, 2017
Net loss from operations $ (213,000) $ (1,404,000)    
Prosperity Bank [Member]        
Credit facility current borrowing capacity $ 1,250,000   $ 1,250,000 $ 3,000,000
Current funds drawn     $ 0  

Income Taxes
v3.7.0.1
Income Taxes
3 Months Ended
Mar. 31, 2017
Income Taxes [Abstract]  
Income Taxes

(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 March 31, 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 March 31, 2017.

 


Income Taxes (Narrative) (Details)
v3.7.0.1
Income Taxes (Narrative) (Details) - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Income Taxes [Abstract]      
Provision or benefit for income taxes  
Unrecognized tax benefits $ 0    
Federal net operating loss carryforwards     $ 26,400,000

Capital Stock
v3.7.0.1
Capital Stock
3 Months Ended
Mar. 31, 2017
Stockholders' equity  
Capital Stock

(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 was approximately $177,000.



Rights Agreement

Effective March 17, 2017 the Board of Directors of Tengasco, Inc. 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

No shares of Series A Preferred Stock have been issued by the Company pursuant to the Rights Agreement described above or otherwise.


Capital Stock (Narrative) (Details)
v3.7.0.1
Capital Stock (Narrative) (Details)
3 Months Ended
Mar. 27, 2017
$ / shares
Feb. 13, 2017
USD ($)
shares
Jan. 04, 2017
item
shares
Mar. 31, 2017
USD ($)
shares
Dec. 31, 2016
shares
Capital Stock [Line Items]          
Costs of stock issuance in rights offering | $       $ 37,000  
Number of directors | item     4    
Proceeds from stock issuance in rights offering | $       $ 2,699,000  
Rights Plan [Member]          
Capital Stock [Line Items]          
Number of preferred share purchase right for each outstanding share of its common stock to shareholder | $ / shares $ 1        
Common stock, Threshold for exercise of rights percentage 4.95%        
Rights [Member]          
Capital Stock [Line Items]          
Common stock, New shares issued | shares   4,498,698      
Costs of stock issuance in rights offering | $   $ 177,000      
Proceeds from stock issuance in rights offering | $   $ 2,700,000      
Directors, CFO And Interim CEO [Member]          
Capital Stock [Line Items]          
Common stock, New shares issued | shares     5,264    
Directors, Management, And Affiliates [Member] | Rights [Member]          
Capital Stock [Line Items]          
Common stock, New shares issued | shares   3,293,407      
Series A Preferred Stock [Member]          
Capital Stock [Line Items]          
Preferred stock, shares issued | shares       0 0

Earnings Per Common Share
v3.7.0.1
Earnings Per Common Share
3 Months Ended
Mar. 31, 2017
Earnings Per Common Share [Abstract]  
Earnings Per Common Share

(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 Three Months Ended



 

March 31,



 

2017

 

2016

Income (numerator):

 

 

 

 

 

 

Net loss

 

$

(213)

 

$

(1,404)

Weighted average shares (denominator):

 

 

 

 

 

 

Weighted average shares – basic

 

 

8,452,132 

 

 

6,084,241 

Dilution effect of share-based compensation, treasury method

 

 

 —

 

 

 —

Weighted average shares – dilutive

 

 

8,452,132 

 

 

6,084,241 

Loss per share – Basic and Dilutive:

 

 

 

 

 

 

Basic and Dilutive

 

$

(0.03)

 

$

(0.23)




Earnings Per Common Share (Tables)
v3.7.0.1
Earnings Per Common Share (Tables)
3 Months Ended
Mar. 31, 2017
Earnings Per Common Share [Abstract]  
Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share



 

 

 

 

 

 



 

 

 

 

 

 



 

For the Three Months Ended



 

March 31,



 

2017

 

2016

Income (numerator):

 

 

 

 

 

 

Net loss

 

$

(213)

 

$

(1,404)

Weighted average shares (denominator):

 

 

 

 

 

 

Weighted average shares – basic

 

 

8,452,132 

 

 

6,084,241 

Dilution effect of share-based compensation, treasury method

 

 

 —

 

 

 —

Weighted average shares – dilutive

 

 

8,452,132 

 

 

6,084,241 

Loss per share – Basic and Dilutive:

 

 

 

 

 

 

Basic and Dilutive

 

$

(0.03)

 

$

(0.23)




Earnings Per Common Share (Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share) (Details)
v3.7.0.1
Earnings Per Common Share (Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share) (Details) - USD ($)
$ / shares in Units, $ in Thousands
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Earnings Per Common Share [Abstract]    
Net loss $ (213) $ (1,404)
Weighted average shares - basic 8,452,132 6,084,241
Dilution effect of share-based compensation, treasury method
Weighted average shares - dilutive 8,452,132 6,084,241
Basic and fully diluted $ (0.03) $ (0.23)

Recent Accounting Pronouncements
v3.7.0.1
Recent Accounting Pronouncements
3 Months Ended
Mar. 31, 2017
Recent Accounting Pronouncements [Abstract]  
Recent Accounting Pronouncements

(6)  Recent Accounting Pronouncements



In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2016-12, which deferred the effective date of ASU 2014-09 and provided additional implementation guidance. The standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are currently assessing the potential impact, but the Company does not believe the adoption of the standard will have a significant impact on our consolidated financial statements and results of operations.



In November 2015, the FASB issued ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred TaxesThis guidance eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent.  This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  The Company will apply the amendments retrospectively to all periods presented.  There was no impact on the Company’s operating results or cash flows.



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



In March 2016, the FASB issued Update 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.  This guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. There was no impact on the Company’s 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.



 


Related Party Transactions
v3.7.0.1
Related Party Transactions
3 Months Ended
Mar. 31, 2017
Related Party Transactions [Abstract]  
Related Party Transactions

 (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 March 31, 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 well as certain private parties.  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 March 31, 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 March 31, 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 March 31, 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 March 31, 2017 and December 31, 2016.

 


Related Party Transactions (Narrative) (Details)
v3.7.0.1
Related Party Transactions (Narrative) (Details) - USD ($)
3 Months Ended
Dec. 18, 2007
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Related Party Transaction [Line Items]        
Methane gas revenue   $ 0 $ 0  
Working interest percent 15.00%      
Bond, face value   0    
Related party allowance for doubtful accounts receivable   14,000   $ 14,000
Accounts receivable - related parties balance    
Methane Project [Member]        
Related Party Transaction [Line Items]        
Percent of net profits, interest   7.50%    
Hoactzin Partners, L.P. [Member]        
Related Party Transaction [Line Items]        
Related parties accounts payable   $ 159,000   159,000
Past due related parties accounts payable   159,000    
Hoactzin Partners, L.P. [Member] | Methane Project [Member]        
Related Party Transaction [Line Items]        
Methane gas revenue   0    
Net profits   0    
Related Party [Member]        
Related Party Transaction [Line Items]        
Related party allowance for doubtful accounts receivable   159,000   159,000
Related Party [Member] | Hoactzin Partners, L.P. [Member]        
Related Party Transaction [Line Items]        
Accounts receivable-related party, allowance for doubtful accounts   $ 159,000    
Accounts receivable - related parties balance       $ 0

Oil And Gas Properties
v3.7.0.1
Oil And Gas Properties
3 Months Ended
Mar. 31, 2017
Oil And Gas Properties [Abstract]  
Oil And Gas Properties

(8)  Oil and Gas Properties



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







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Oil and gas properties

 

$

5,373 

 

$

5,315 

Unevaluated properties

 

 

48 

 

 

106 

Accumulated depreciation, depletion, and amortization

 

 

(401)

 

 

(196)

Oil and gas properties

 

$

5,020 

 

$

5,225 



The Company recorded depletion expense of $204,000 and $302,000 for the three months ended March 31, 2017 and 2016, respectively.  During the three months ended March 31, 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $1,000 gain on asset retirement obligations.  In addition, during the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017As a result of the ceiling test impairments during 2015 and the first three quarters of 2016, the accumulated depreciation, depletion, and amortization was been 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, this amount was not netted against cost, but remained in accumulated depreciation, depletion, and amortization at December 31, 2016 and March 31, 2017.

 


Oil And Gas Properties (Tables)
v3.7.0.1
Oil And Gas Properties (Tables)
3 Months Ended
Mar. 31, 2017
Oil And Gas Properties [Abstract]  
Schedule Of Oil And Gas Properties



 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Oil and gas properties

 

$

5,373 

 

$

5,315 

Unevaluated properties

 

 

48 

 

 

106 

Accumulated depreciation, depletion, and amortization

 

 

(401)

 

 

(196)

Oil and gas properties

 

$

5,020 

 

$

5,225 




Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details)
v3.7.0.1
Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details) - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Dec. 31, 2016
Oil And Gas Properties [Abstract]      
Oil and gas properties $ 5,373,000   $ 5,315,000
Unevaluated properties 48,000   106,000
Accumulated depreciation, depletion, and amortization (401,000)   (196,000)
Oil and gas properties 5,020,000   $ 5,225,000
Depletion expense 204,000 $ 302,000  
Impairment 0 $ 641,000  
Gain on asset retirement obligations $ 1,000    

Asset Retirement Obligation
v3.7.0.1
Asset Retirement Obligation
3 Months Ended
Mar. 31, 2017
Asset Retirement Obligation [Abstract]  
Asset Retirement Obligation

(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 three months ended March 31, 2017 (in thousands):







 

 

 



 

 

 

Balance December 31, 2016

 

$

2,046 

Accretion expense

 

 

36 

Liabilities incurred

 

 

 —

Liabilities settled

 

 

(11)

Balance March 31, 2017

 

$

2,071 

 


Asset Retirement Obligation (Tables)
v3.7.0.1
Asset Retirement Obligation (Tables)
3 Months Ended
Mar. 31, 2017
Asset Retirement Obligation [Abstract]  
Asset Retirement Obligation Transactions



 

 

 



 

 

 

Balance December 31, 2016

 

$

2,046 

Accretion expense

 

 

36 

Liabilities incurred

 

 

 —

Liabilities settled

 

 

(11)

Balance March 31, 2017

 

$

2,071 




Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details)
v3.7.0.1
Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Asset Retirement Obligation [Abstract]    
Balance $ 2,046  
Accretion expense 36 $ 36
Liabilities incurred  
Liabilities settled (11)  
Balance $ 2,071  

Long-Term Debt
v3.7.0.1
Long-Term Debt
3 Months Ended
Mar. 31, 2017
Long-Term Debt [Abstract]  
Long-Term Debt

(10)  Long-Term Debt



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







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Note payable to a financial institution, with interest only payment until maturity

 

$

 —

 

$

2,400 

Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10

 

 

87 

 

 

102 

Total debt

 

 

87 

 

 

2,502 

Less current maturities

 

 

(53)

 

 

(55)

Long-term debt, less current maturities

 

$

34 

 

$

2,447 





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 was approximately $24,000.



At March 31, 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 March 31, 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 March 31, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio.  During the quarter ended March 31, 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 March 31, 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)

 


Long-Term Debt (Tables)
v3.7.0.1
Long-Term Debt (Tables)
3 Months Ended
Mar. 31, 2017
Long-Term Debt [Abstract]  
Schedule Of Long-Term Debt To Unrelated Entities



 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Note payable to a financial institution, with interest only payment until maturity

 

$

 —

 

$

2,400 

Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10

 

 

87 

 

 

102 

Total debt

 

 

87 

 

 

2,502 

Less current maturities

 

 

(53)

 

 

(55)

Long-term debt, less current maturities

 

$

34 

 

$

2,447 




Long-Term Debt (Narrative) (Details)
v3.7.0.1
Long-Term Debt (Narrative) (Details)
$ in Thousands
3 Months Ended
Mar. 16, 2017
USD ($)
Mar. 31, 2017
USD ($)
Mar. 15, 2017
USD ($)
Dec. 31, 2016
USD ($)
Debt Instrument [Line Items]        
Unamortized debt issuance costs       $ 24
Prosperity Bank [Member]        
Debt Instrument [Line Items]        
Credit facility maturity date   Jul. 31, 2018    
Rate above prime   0.50%    
Interest rate 4.50%      
Credit facility maximum borrowing capacity   $ 40,000    
Credit facility current borrowing capacity $ 1,250 1,250 $ 3,000  
Prosperity Bank [Member] | Loans And Letters Of Credit [Member]        
Debt Instrument [Line Items]        
Credit facility maximum borrowing capacity   $ 40,000    
Maximum [Member]        
Debt Instrument [Line Items]        
Interest rate per annum   4.60%    
Maximum [Member] | Prosperity Bank [Member]        
Debt Instrument [Line Items]        
Funded debt to EBITDA 3.5      
Minimum [Member]        
Debt Instrument [Line Items]        
Interest rate per annum   4.16%    
Minimum [Member] | Prosperity Bank [Member]        
Debt Instrument [Line Items]        
Current ratio 1      
Interest coverage 3.0      

Long-Term Debt (Schedule Of Long-Term Debt To Unrelated Entities) (Details)
v3.7.0.1
Long-Term Debt (Schedule Of Long-Term Debt To Unrelated Entities) (Details) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2017
Dec. 31, 2016
Debt Instrument [Line Items]    
Note payable to financial institution, with interest only payment until maturity   $ 2,400
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 $ 87 102
Total debt 87 2,502
Less current maturities (53) (55)
Long-term debt, less current maturities 34 $ 2,447
Periodic payments including interest, insurance and maintenance $ 10  
Maximum [Member]    
Debt Instrument [Line Items]    
Interest rate per annum 4.60%  
Minimum [Member]    
Debt Instrument [Line Items]    
Interest rate per annum 4.16%  

Manufactured Methane
v3.7.0.1
Manufactured Methane
3 Months Ended
Mar. 31, 2017
Manufactured Methane [Abstract]  
Manufactured Methane

(11)  Manufactured Methane



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







 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Manufactured Methane facilities, at cost

 

$

1,681 

 

$

1,681 

Accumulated depreciation

 

 

(137)

 

 

(122)

Manufactured Methane facilities, net

 

$

1,544 

 

$

1,559 



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 $15,000 for the three months ended March 31, 2017 and 2016.

 


Manufactured Methane (Tables)
v3.7.0.1
Manufactured Methane (Tables)
3 Months Ended
Mar. 31, 2017
Manufactured Methane [Abstract]  
Methane Facilities



 

 

 

 

 

 



 

 

 

 

 

 



 

March 31,

 

December 31,



 

2017

 

2016

Manufactured Methane facilities, at cost

 

$

1,681 

 

$

1,681 

Accumulated depreciation

 

 

(137)

 

 

(122)

Manufactured Methane facilities, net

 

$

1,544 

 

$

1,559 




Manufactured Methane (Narrative) (Details)
v3.7.0.1
Manufactured Methane (Narrative) (Details) - Methane Project [Member] - USD ($)
3 Months Ended
Mar. 31, 2017
Mar. 31, 2016
Methane Project [Line Items]    
Date methane facilities were placed into service Apr. 01, 2009  
Methane facilities estimated useful life 25 years  
Landfill closure date Dec. 01, 2041  
Depreciation expense $ 15,000 $ 15,000

Manufactured Methane (Methane Facilities) (Details)
v3.7.0.1
Manufactured Methane (Methane Facilities) (Details) - Methane Project [Member] - USD ($)
$ in Thousands
Mar. 31, 2017
Dec. 31, 2016
Property, Plant and Equipment [Line Items]    
Manufactured Methane facilities, at cost $ 1,681 $ 1,681
Accumulated depreciation (137) (122)
Manufactured Methane facilities, net $ 1,544 $ 1,559

Fair Value Measurements
v3.7.0.1
Fair Value Measurements
3 Months Ended
Mar. 31, 2017
Fair Value Measurements [Abstract]  
Fair Value Measurements

(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 March 31, 2017 and December 31, 2016.

 


Commitments And Contingencies
v3.7.0.1
Commitments And Contingencies
3 Months Ended
Mar. 31, 2017
Commitments And Contingencies [Abstract]  
Commitments And Contingencies

(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 March 31, 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.



 


Commitments And Contingencies (Narrative) (Details)
v3.7.0.1
Commitments And Contingencies (Narrative) (Details)
3 Months Ended
Mar. 31, 2017
$ / bbl
Sep. 30, 2015
USD ($)
Incidence Of Non-Compliance [Member]    
Loss Contingencies [Line Items]    
Maximum potential loss | $   $ 386,000
Minimum [Member]    
Loss Contingencies [Line Items]    
Compensation reduction until WTI posting 70  
Compensation reimbursement at WTI posting 85