U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018March 31, 2019

Commission File No. 1-15555

Tengasco, Inc.
(Exact name of registrant as specified in its charter)

Delaware 87-0267438
(State or other jurisdiction of incorporation or organization) (IRS Employer Identification No.)

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 every Interactive Data File required to be submitted 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 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.

Large accelerated filer 
Accelerated filer 
Non-accelerated filer 
Smaller reporting company 

Emerging growth company 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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

Securities registered pursuant to Section 12(b) of the Act:

Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockTGCNYSE American

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,639,29010,648,663 common shares at November 5, 2018May 6, 2019.



TABLE OF CONTENTS

  PAGE
PART I.FINANCIAL INFORMATION 
 ITEM 1. FINANCIAL STATEMENTS 
 3
 5
 6
 7
 1718
 2019
 21
PART II.21
 21
 21
 21
 21
 21
 21
 22
 23
 *    CERTIFICATIONS 

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

 
September 30,
2018
  
December 31,
2017
  
March 31,
2019
  
December 31,
2018
 
Assets            
            
Current            
Cash and cash equivalents $3,402  $185  $3,224  $3,115 
Accounts receivable, less allowance for doubtful accounts of $14  695   517 
Accounts receivable – related party, less allowance for doubtful accounts of $159      
Accounts receivable  608   533 
Inventory  646   541   423   464 
Other current assets  173   134 
Discontinued operations included in current assets     121 
Prepaid expenses  226   235 
Total current assets  4,916   1,498   4,481   4,347 
Loan fees, net  10   13   7   9 
Right of use asset - operating leases  84    
Oil and gas properties, net (full cost accounting method)
  4,839   4,720   4,650   4,804 
Other property and equipment, net  212   135   169   190 
Accounts receivable - noncurrent  121   242   130   130 
Discontinued operations included in non-current assets     1,497 
Other noncurrent assets  4   4 
Total assets $10,098  $8,105  $9,525  $9,484 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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

 
September 30,
2018
  
December 31,
2017
  
March 31,
2019
  
December 31,
2018
 
Liabilities and Stockholders’ Equity            
            
Current liabilities            
Accounts payable – trade $361  $181  $173  $132 
Accounts payable – other  159   159 
Accrued and other current liabilities  250   187 
Accrued liabilities  267   282 
Lease liabilities - operating leases - current  59    
Lease liabilities - finance leases - current  77    
Current maturities of long-term debt  60   41      51 
Discontinued operations included in current liabilities     43 
Asset retirement obligation - current  83   83 
Total current liabilities  830   611   659   548 
Asset retirement obligation  2,363   2,270 
Lease liabilities - operating leases - noncurrent  25    
Lease liabilities - finance leases - noncurrent  35    
Long term debt, less current maturities  76   49      73 
Asset retirement obligation - noncurrent  2,131   2,096 
Total liabilities  3,269   2,930   2,850   2,717 
Commitments and contingencies (Note 13)                
Stockholders’ equity                
Preferred stock, 25,000,000 shares authorized:                
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding            
Common stock, $.001 par value, authorized 100,000,000 shares, 10,624,493 and 10,619,924 shares issued and outstanding  11   11 
Common stock, $.001 par value, authorized 100,000,000 shares; 10,644,252 and 10,639,290 shares issued and outstanding  11   11 
Additional paid–in capital  58,257   58,253   58,280   58,276 
Accumulated deficit  (51,439)  (53,089)  (51,616)  (51,520)
Total stockholders’ equity  6,829   5,175   6,675   6,767 
Total liabilities and stockholders’ equity $10,098  $8,105  $9,525  $9,484 

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)


 
For the Three Months Ended
September 30,
  
For the Nine Months Ended
September 30,
  
For the Three Months Ended
March 31,
 
 2018  2017  2018  2017  2019  2018 
Revenues                  
Oil and gas properties $1,654  $1,035  $4,497  $3,383  $1,171  $1,367 
Total revenues  1,654   1,035   4,497   3,383   1,171   1,367 
Cost and expenses                        
Production costs and taxes  862   907   2,502   2,595   779   730 
Depreciation, depletion, and amortization  219   210   599   658   184   183 
General and administrative  288   268   896   860   346   336 
Total cost and expenses  1,369   1,385   3,997   4,113   1,309   1,249 
Net income (loss) from operations  285   (350)  500   (730)  (138)  118 
Other income (expense)                
Interest expense  (1)  (16)  (4)  (36)
Other expense        
Net interest expense  (3)  (1)
Gain on sale of assets  14   5   34   5   45   16 
Total other income (expense)  13   (11)  30   (31)
Net income (loss) from operations before income tax  298   (361)  530   (761)
Total other expenses  42   15 
Income (loss) from continuing operations before income tax  (96)  133 
Deferred income tax benefit                  
Net income (loss) from continuing operations  298   (361)  530   (761)  (96)  133 
Net income from discontinued operations     46   1,120   55      1,110 
Net income (loss) $298  $(315) $1,650  $(706) $(96) $1,243 
Net income (loss) per share - basic and fully diluted                
Net income (loss) per share - Basic and Fully Diluted        
Continuing operations $0.03  $(0.03) $0.05  $(0.08) $(0.01) $0.01 
Discontinued operations $0.00  $0.00  $0.11  $0.01  $  $0.10 
Shares used in computing earnings per share                        
Basic and fully diluted  10,624,493   10,614,402   10,624,476   9,899,696   10,644,197   10,624,442 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Tengasco, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(unaudited)
(in thousands)

 
For the Nine Months Ended
September 30,
  
For the Three Months Ended
March 31,
 
 2018  2017  2019  2018 
Operating activities            
Net income (loss) from continuing operations $530  $(761) $(96) $133 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:                
Depreciation, depletion, and amortization  599   658   184   183 
Amortization of loan fees-interest expense  3   11   2   1 
Accretion on asset retirement obligation  106   107   35   36 
(Gain) loss on asset sales  (34)  (5)
Gain on asset sales  (45)  (16)
Stock based compensation  4   11   4   4 
Changes in assets and liabilities:                
Accounts receivable  (57)  90   (75)  (33)
Inventory and other assets  (144)  110   (55)  (200)
Accounts payable  (14)  (122)  50   (48)
Accrued and other current liabilities  30   113   (15)  18 
Settlement on asset retirement obligation  (5)  (21)  (7)  (7)
Net cash provided by operating activities - continuing operations  1,018   191 
Net cash provided by (used in) operating activities - discontinued operations  45   23 
Net cash provided by operating activities  1,063   214 
Net cash provided by (used in) operating activities - continuing operations  (18)  71 
Net cash provided by operating activities - discontinued operations     67 
Net cash provided by (used in) operating activities  (18)  138 
Investing activities                
Additions to oil and gas properties  (453)  (147)  (11)  (32)
Proceeds from sale of oil and gas properties  7   6      3 
Additions to other property and equipment  (28)  (12)     (19)
Proceeds from sale of other property and equipment  8         7 
Net cash used in investing activities - continuing operations  (466)  (153)
Proceeds from sale of materials inventory  150    
Net cash provided by (used in) investing activities - continuing operations  139   (41)
Net cash provided by investing activities - discontinued operations  2,650         2,650 
Net cash provided by (used in) investing activities  2,184   (153)
Net cash provided by investing activities  139   2,609 
Financing activities                
Repayments of borrowings  (130)  (2,844)  (12)  (116)
Proceeds from borrowings  100   400      100 
Proceeds from stock issuance in rights offering     2,699 
Cost of stock issuance in rights offering     (102)
Net cash provided by (used in) financing activities - continuing operations  (30)  153 
Net cash used in financing activities - continuing operations  (12)  (16)
Net cash provided by (used in) financing activities - discontinued operations            
Net cash provided by (used in) financing activities  (30)  153 
Net cash used in financing activities  (12)  (16)
Net change in cash and cash equivalents  3,217   214   109   2,731 
Cash and cash equivalents, beginning of period  185   76   3,115   185 
Cash and cash equivalents, end of period $3,402  $290  $3,224  $2,916 
Supplemental cash flow information:                
Cash interest payments $  $25  $1  $ 
Supplemental non-cash investing and financing activities:                
Financed company vehicles, net of trade-ins $76  $27 
Cost of stock issuance in rights offering $  $(140)
Asset retirement obligations incurred $  $1 
Financed company vehicles $  $109 
Capital expenditures included in accounts payable and accrued liabilities $227  $  $  $6 

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(1)Description of Business and Significant Accounting Policies

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

The Company’s wholly-owned subsidiary, 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”) operated 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.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018 for $2.65 million. (See Note 11. Discontinued Operations)

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of September 30,March 31, 2019 and March 31, 2018 and September 30, 2017 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, 20172018 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 ninethree months ended September 30, 2018March 31, 2019 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018.2019. 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, 2017.2018.

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

Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with CustomersThe Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and 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.

Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials.  Crude oil that is produced is stored in storage tanks.  The Company will contact the purchaser and request them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.  When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis.  Fees and other deductions incurred prior to transfer of control are recorded as production costs.  Revenues are reported net of fees and other deductions incurred after transfer of control.

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Electricity from the Company’s methane facility was sold on a long term contract.  There werewas no specific volumesquantity of electricity that werewas required to be delivered under this contract.  Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognizedThe Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations.  (See Note 11. Discontinued Operations)

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The Company operates certain salt water disposal wells, some of which accept water from third parties.  The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells.  In some cases, the contract is based on a per barrel charge to dispose water into the wells.  There is no requirement under the contracts for these third parties to use these wells for their water disposal.  If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month.

The following table presents the disaggregated revenue by commodity for the three months ended March 31, 2019 and nine months ended September 30, 2018 and 2017 (in(in thousands):

 Three Months Ended  Nine Months Ended  
March 31,
2019
  
March 31,
2018
 
 September 30, 2018  September 30, 2017  September 30, 2018  September 30, 2017       
Revenues (in thousands):            
Crude oil $1,647  $1,028  $4,472  $3,360  $1,164  $1,357 
Salt water disposal fees  7   7   25   23   7   10 
                
Total $1,654  $1,035  $4,497  $3,383  $1,171  $1,367 

There were no natural gas imbalances at September 30, 2018March 31, 2019 or December 31, 2017.2018.

Cash and Cash Equivalents

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

Inventory

Inventory consists of crude oil in tanks and is carried at lower of cost or market value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended September 30, 2018March 31, 2019 and December 31, 2017.2018.  These costs includesinclude production costs and taxes, allocated general and administrative costs, depletion, and allocated interest cost.taxes.  The market value component is calculated using the average September 2018March 2019 and December 20172018 oil sales prices received from the Company’s Kansas properties.  In addition, at December 31, 2018, the Company also carried equipment and materials to be used in its Kansas operation and iswas carried at the lower of cost or market value.  The equipment inventory was sold to a third party during the three months ended March 31, 2019.  The cost component of the equipment and materials inventory representsrepresented the original cost paid for the equipment and materials.  The market component is based on estimated sales value for similar equipment and materials at the end of each period.  At September 30, 2018March 31, 2019 and December 31, 2017,2018, inventory consisted of the following (in thousands):

 
September 30,
2018
  
December 31,
2017
  
March 31,
2019
  
December 31,
2018
 
Oil – carried at cost $541  $436  $423  $359 
Equipment and materials – carried at market  105   105      105 
Total inventory $646  $541  $423  $464 

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 acquisitions, 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. since 2009. 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 $0 in unevaluated properties as of September 30, 2018March 31, 2019 and $23,000 at December 31, 2017.2018.  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.

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10%  plus cost of properties not being amortized and the lower of cost or estimated  fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down may not be reversed in a later period.  The Company did not record any impairment of its oil and gas properties during the ninethree months ended September 30, 2018March 31, 2019 and 2017.2018.

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. AnThere was no allowance was recorded at September 30, 2018March 31, 2019 and December 31, 2017.2018.

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

 
September 30,
2018
 
December 31,
2017
 
March 31,
2019
  
December 31,
2018
 
Revenue $ 510 $ 479 $474  $396 
Tax  121  —  129   129 
Joint interest  54  23  5   8 
Other  24  29
Allowance for doubtful accounts   (14)   (14)
Total accounts receivable $ 695 $ 517
Accounts receivable - current $608  $533 
        
Tax - noncurrent $130  $130 

At September 30, 2018March 31, 2019 and December 31, 2017,2018, the Company recorded a tax related non-currentcurrent receivable in the amounts of $121,000$129,000 and $242,000, respectively.  At September 30, 2018, based upon its expected recovery, the Company reclassified $121,000 of thisa tax related non-current receivable as a current receivable.of $130,000.  (See Note 3. Income Taxes)

Reclassifications

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

(2)LiquidityChanges in Stockholders’ Equity

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility 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 borrowing base of $3 million, subject to a credit limit based on current covenants of approximately $2.74 million, 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.
Three Months Ended March 31, 2019:

  Common Stock

Paid-in
Capital


Accumulated
Deficit


 Total
  Shares  Amount
Balance, December 31, 2018  10,639,290  $11  $58,276  $(51,520) $6,767 
                     
Net loss           (96)  (96)
Compensation expense related to stock issued  4,962      4      4 
                     
Balance, March 31, 2019  10,644,252  $11  $58,280  $(51,616) $6,675 

9

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Three Months Ended March 31, 2018:

  Common Stock

Paid-in
Capital


Accumulated
Deficit


 Total
  Shares  Amount
Balance, December 31, 2017  10,619,924  $11  $58,253  $(53,089) $5,175 
                     
Net income           1,243   1,243 
Compensation expense related to stock issued  4,569      4      4 
                     
Balance, March 31, 2018  10,624,493  $11  $58,257  $(51,846) $6,422 

(3)Income Taxes

Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates.  In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

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 has computed an estimated annual effective tax rate for the current reporting year of 0% based upondiffers from the year-to-date and forecasted book income and cumulative loss position forstatutory rate of 21% due primarily to adjustments to the three year period ended December 31, 2018.  Accordingly,valuation allowance on the Company has recorded no provision or benefit for income taxes for the current reporting period.deferred tax assets.

At December 31, 2017,2018, federal net operating loss carryforwards amounted to approximately $34.8$35.6 million, of which expire$34.6 million expires between 2019 and 2036. In 2017, the2037 which can offset 100% of taxable income and $1 million that has an indefinite carryforward period which can offset 80% of taxable income per year.  The Company releasedhas approximately $260,000 in refundable credits, and it expects that a substantial portion will be refunded between 2018 and 2021.  As 50% of the valuation allowance related tocredit will be refunded when we file the Company’s Minimum Tax Credit (“MTC”)2018 tax return, this amount is recorded as a resultcurrent accounts receivable on the Balance Sheet at March 31, 2019 and December 31, 2018, with balance of the 2017 Tax Act.  The net total deferred tax asset of $242,000 wasthis refund recorded as a non-current receivable at December 31, 2017.  At September 30, 2018, based upon its expected recovery, the Company reclassified $121,000 of this tax related non-current receivable as a currentaccounts receivable.  The Company recorded a valuation allowance on the remaining deferred tax assets at September 30, 2018March 31, 2019 and December 31, 20172018 as such amounts were not considered to be more-likely-than-not realizable due to cumulative losses incurred during the preceding 3 year period.  There were no recorded unrecognized tax benefits at September 30,March 31, 2019 and December 31, 2018.

(4)Capital Stock

Common Stock

There were noOn January 2, 2019, the Company issued 4,962 shares of common shares issued during the three months ended September 30, 2018.

On October 1, 2018, 14,797 common shares were issuedstock in the aggregate to the Company’s fourthree directors and CFO and interim CEO.

On April 1, 2019, the Company issued 4,411 shares of common stock in the aggregate to the Company’s three 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.

10

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 if the Company’s experiences 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.

10

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The Rights will expire prior to the earlier of March 16, 2020; or 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 $0.0001 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 Three Months Ended
September 30,
  
For the Nine Months Ended
September 30,
  
For the Three Months Ended
March 31,
 
 2018  2017  2018  2017  2019  2018 
Income (numerator):                  
Net income (loss) from continuing operations $298  $(361) $530  $(761) $(96) $133 
Net income from discontinued operations $  $46  $1,120  $55  $  $1,110 
Weighted average shares (denominator):                        
Weighted average shares – basic  10,624,493   10,614,402   10,624,476   9,899,696   10,644,197   10,624,442 
Dilution effect of share-based compensation, treasury method                  
Weighted average shares – dilutive  10,624,493   10,614,402   10,624,476   9,899,696   10,644,197   10,624,442 
Income (loss) per share – Basic and Dilutive:                        
Continuing operations $0.03  $(0.03) $0.05  $(0.08) $(0.01) $0.01 
Discontinued operations $0.00  $0.00  $0.11  $0.01  $  $0.10 

Options issued to the Company’s directors in which the exercise prices wereprice was higher than the average market price each quarter were excluded from diluted shares.shares as they would have been anti-dilutive.  In addition, the shares that would be issued to employees and Company directors if the thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel have also been excluded from this calculation.  (See Note 13. Commitments and Contingencies)

11

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(6)Recent Accounting Pronouncements

In February 2016, the FASB issued UpdateASU 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. 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.  To date, theThe Company has identified each of its leases and is in the process of determiningdetermined the impact of this new guidance on each of the identified leases.  The Company does not expectimplemented ASU 2016-02 Leases (Topic 842) as of January 1, 2019 using the modified retrospective approach.  As a result of this to impact its operating results or cash flows, however,implementation, the Company does expectrecorded right-of-use assets and liabilities associated with operating leases of approximately $98,000.  There was no transition adjustment related to carry a portion of future lease costs as an asset and a liability on its balance sheet.finance leases.

11The Company elected the package of practical expedients within ASU 2016-02 Leases (Topic 842) that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contract are or contain leases, (ii) the lease classification of any expired or existing leases, or (iii) initial direct costs for any existing leases.  Additionally, the Company elected the practical expedient to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date.  The Company also made an account policy election not to apply the lease recognition requirements to leases with an initial term of 12 months or less.

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(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”).  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 startup in April, 2009 through January 26, 2018, the date the Company sold the Methane Project to a third party, for payment to Hoactzin under the net profits interest.  In addition, during the fourth quarter of 2018, the Company acquired all of Hoactzin’s working interest in the drilling program wells for $134,690.

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 effective December 18, 2012 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 listed operator of record on an expired lease owned by Hoactzin where a production platform remains located.  The Company performs no operations on any property in the Gulf including that expired lease and platform, but regulations do not allow removalcertain of the last listed operator on any expired lease.these wells.  As of the date of this Report, the Company continues to administratively assist Hoactzin with this transition process.

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 September 30, 2018 and December 31, 2017 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2018 and December 31, 2017 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 September 30, 2018 and December 31, 2017.  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 September 30, 2018 and December 31, 2017.

(8)Oil and Gas Properties

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

  
September 30,
2018
  
December 31,
2017
 
Oil and gas properties $6,377  $5,704 
Unevaluated properties      
Accumulated depreciation, depletion and amortization  (1,538)  (984)
Oil and gas properties, net $4,839  $4,720 

The Company recorded depletion expense of $546,000 and $608,000 for the nine months ended September 30, 2018 and 2017, respectively.  During the nine months ended September 30, 2018 and 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” an $8,000 gain on asset retirement obligations and a $2,000 gain on asset retirement obligations, respectively.
  
March 31,
2019
  
December 31,
2018
 
Oil and gas properties $6,528  $6,503 
Unevaluated properties     23 
Accumulated depreciation, depletion, and amortization  (1,878)  (1,722)
Oil and gas properties $4,650  $4,804 

12

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

The Company recorded depletion expense of $163,000 and $172,000 for the three months ended March 31, 2019 and 2018, respectively.  During the three months ended March 31, 2019 and 2018, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $(7,000) loss on asset retirement obligations and a $7,000 gain on asset retirement obligations, respectively.

(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 ninethree months ended September 30, 2018March 31, 2019 (in thousands):

Balance December 31, 2017 $2,270 
Balance December 31, 2018 $2,179 
Accretion expense  106   35 
Liabilities incurred      
Liabilities settled  (13)   
Balance September 30, 2018 $2,363 
Balance March 31, 2019 $2,214 

(10)Long-Term Debt and Lease Liabilities

Long Term Debt

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

  
September 30,
2018
  
December 31,
2017
 
Note payable to a financial institution, with interest only payment until maturity. $  $ 
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 $5  136   90 
Total  long-term debt  136   90 
Less current maturities  (60)  (41)
Long-term debt, less current maturities $76  $49 
  
March 31,
2019
  
December 31,
2018
 
Note payable to a financial institution, with interest only payment until maturity $  $ 
Installment notes bearing interest at the rate of 5.0% to 6.5% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $5     124 
Total debt     124 
Less current maturities     (51)
Long-term debt, less current maturities $  $73 

At September 30, 2018,March 31, 2019, installment notes are recorded to Lease liabilities – finance leases.

At March 31, 2019, the Company had a revolving credit facility with Prosperity Bank.  This has historically been 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 $50 million or the Company’s borrowing base in effect from time to time. As of September 30, 2018,March 31, 2019, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility includes certain covenants with which the Company is required to comply.  At September 30, 2018,March 31, 2019, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At September 30, 2018,March 31, 2019, the interest rate on this credit facility was 5.75%6.00%.  The Company was in compliance with all covenants during the quarter ended September 30, 2018.

On August 24, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.March 31, 2019.  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 5.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30,March 31, 2019 or December 31, 2018.  The next borrowing base review will take place in MarchMay 2019.

On March 21,Lease Liabilities

Effective January 1, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s reviewCompany adopted ASU 2016-02 Leases (Topic 842).  We determined if a contract is a lease at inception of the Company’s owned producing properties was amended to increasearrangement.  To the borrowing base to $2 million and the maturity date was extended to July 31, 2020.  The borrowing base remained subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.00% at the dateextent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease.  As of the amendment.  The maximum line of credit ofJanuary 1, 2019, the Company undercapitalizes its operating leases on the Prosperity Bank credit facility remained $50 million.Consolidated Balance Sheet as a right of use asset and a corresponding lease liability.  The Company also capitalizes its finance leases on the Consolidated Balance Sheet as other property and equipment and a corresponding lease liability.  The right of use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease.  Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.  Short term leases that have an initial term of one year or less are not capitalized unless the Company intends to renew the lease to extend the initial term past one year.

13

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

We lease certain office space, a storage yard, and field vehicles to support our operations.  A more detailed description of the Company’s lease types is included below.

Office and Storage Yard

The Company maintains an office to support its corporate operations.  This office agreement is with a third party and was structured with a 39 month initial term.  The Company can renew the lease for 36 additional months by providing to the Landlord written notice of intent to exercise the renewal not less than nine months prior to expiration of the initial term.  The Company’s corporate office lease is classified as an operating lease.

The Company maintains an office to support its field operations.  This office is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability.  The Company’s field office lease is classified as an operating lease.

The Company maintains a yard to store certain equipment used in its field operations.  This storage yard agreement is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability.  The Company’s storage yard is classified as an operating lease.

Field Vehicles

The Company leases certain vehicles from a third party for use in its field operations.  The lease term for each vehicle is based on expected daily use of the vehicles by the field personnel, typically between 18 and 36 months.  The Company also pays an upfront fee at the commencement of the lease term.  The Company can continue to lease the vehicles past the initial lease term on a month-to-month basis.  In addition, each vehicle has a residual value guarantee at the end of the lease term.  The Company’s field vehicle leases are classified as finance leases.

Significant Judgements

In order to determine whether the Company’s contracts contain a lease component, the Company is required to excise significant judgement.  The Company will review each contract to determine if: an asset is specified in the contract; the asset is physically distinct; the supplier does not have substantive substitution rights; the Company obtains substantially all economic benefit from use of the asset; and the Company can direct the use of the asset.  The Company also determines the appropriate discount rate to use on each lease.  If there is a stated rate in the contract, the Company will use the stated rate as its discount rate.  The contract associated with the field vehicles includes a stated rate typically between 5% and 6.5%.  These stated rates for the field vehicle agreements were used as the discount rates.  If there is no stated rate, the Company will use its borrowing rate as the discount rate.  The contracts associated with the offices and yard do not include a stated rate.  The Company used its borrowing rate of 6% as the discounts rate for these agreements.

Components of lease costs for the three months ended March 31, 2019 (in thousands):


Income Statement Account March 31, 2019 
Operating lease cost:    

Production costs and taxes $3 

General and administrative  12 
Total operating lease cost  $15 
      
Finance lease cost:     
Amortization of right of use assetsDepreciation, depletion and amortization $21 
Interest on lease liabilitiesNet interest expense  1 
Total finance lease cost  $22 

14

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Supplemental lease related cash flow information for the three months ended March 31, 2019 (in thousands):

  March 31, 2019 
    
Cash paid for amounts included in the measurement of lease liabilities:   
Operating cash flows from operating leases $15 
Operating cash flows from finance leases  1 
Finance cash flows from finance leases  12 
     
Right of use assets obtained in exchange for lease obligations:    
Operating leases  98 

Supplemental lease related balance sheet information as of March 31, 2019 (in thousands):

  March 31, 2019 
Operating Leases   
    
Right of use asset – operating leases $84 
     
Lease liabilities - current $59 
Lease liabilities - noncurrent  25 
Total operating lease liabilities $84 
     
Finance Leases    
     
Other property and equipment, gross $293 
Accumulated depreciation  (124)
Other property and equipment, net $169 
     
Lease liabilities - current $77 
Lease liabilities - noncurrent  35 
Total finance lease liabilities $112 

Weighted average remaining lease term and discount rate as of March 31, 2019:

  Operating Leases  Finance Leases 
       
Weighted average remaining lease term   1.4 years 1.4 years
Weighted average discount rate  6.0%  5.7%

Maturity of lease liabilities as of March 31, 2019 (in thousands):

  Operating Leases  Finance Leases 
       
2019 (April 2019 – December 2019) $46  $65 
2020  42   37 
2021  -   16 
Total lease payments  88   118 
Less imputed interest  (4)  (6)
Total $84  $112 

15

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

(11)Discontinued Operations

The following table sets forth information concerning the Discontinued Operations (in thousands):

  
September 30,
2018
  
December 31,
2017
 
       
Accounts receivable $  $91 
Other current assets     30 
Discontinued operations included in current assets $  $121 
         
Property, plant, and equipment $  $1,681 
Accumulated depreciation, depletion, and amortization     (184)
Discontinued operations included in non-current assets $  $1,497 
         
Accounts payable - trade $  $27 
Accrued and other current liabilities     16 
Discontinued operations included in current liabilities $  $43 

 
For the Three Months Ended
September 30,
  
For the Nine Months Ended
September 30,
  
For the Three Months Ended
March 31,
 
 2018  2017  2018  2017  2019  2018 
                  
Revenues $  $144  $6  $458  $  $6 
Production costs and taxes     (82)  (40)  (356)     (50)
Depreciation, depletion, and amortization     (16)  (4)  (47)     (4)
Interest income        1         1 
Gain on sale of assets        1,157         1,157 
Deferred income tax benefit            
Net income (loss) from discontinued operations $  $46  $1,120  $55 
Net income from discontinued operations $  $1,110 

The Discontinued Operationsoperations are related to the Manufactured Methane facilities.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018 for $2.65 million.

(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:

14

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

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 September 30, 2018March 31, 2019 and December 31, 2017.2018.

(13)Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“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.

16

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

During the second quarter of 2015, the Company received from Hoactzin a copy of a preliminaryan 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 preliminary analysis raised issues other than the “Incident of Non-Compliance” discussed above.  The Company is discussing this preliminary 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.

In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties.  Since September 30, 2018, the Company has entered into a drilling and seismic commitments in the amount of approximately $131,000.  In addition, in the second quarter of 2018, the Company also entered into a seismic commitment in the amount of approximately $32,000.  Work associated with these commitments started in October 2018.  Finally, the Company started drilling a well in August 2018, however, at September 30, 2018 the well was still in the process of being completed.  The completion of this well occurred in October 2018 with a cost of approximately $69,000 being incurred after September 30, 2018.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions were to 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.  In May 2018, oil prices as so calculated exceeded $70 and compensation reverted 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 September 30, 2018,March 31, 2019, the reductions were approximately $445,000.$432,000.  Of the $432,000, approximately $103,000 will be paid in the Company’s common stock.  The $103,000 value represents approximately 100,000 common share valued at $1.03 per share which represents the closing price on March 29, 2019.  The Company has not accrued any liabilities associated with these compensation reductions.

15

Tengasco, Inc. and Subsidiaries
Notes to Unaudited Condensed Consolidated Financial Statements

Legal Proceedings

The Company is not a party to any pending material legal proceeding.   To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company.  To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.

1617

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

Results of Operations and Financial Condition

During the first ninethree months of 2018, 94.42019, 30.0 MBbl gross of oil were sold from the Company’s properties.  Of the 94.430.0 MBbl sold, 73.023.4 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 ninethree months of 20182019 of 73.023.4 MBbl of oil compares to net sales of 76.523.7 MBbl of oil during the first ninethree months of 2017.2018.  The Company’s net revenue from its oil and gas properties was $4.5$1.2 million during the first ninethree months of 20182019 compared to $3.4$1.4 million during the first ninethree months of 2017.2018.  This increasedecrease in net revenue was primarily due to a $1.3 million increase$175,000 decrease related to an $17.35$7.48 per barrel increasedecrease in the average oil price from $43.92$57.36 per barrel during the first ninethree months of 20172018 to $61.27$49.88 per barrel during the first ninethree months of 2018, partially offset by2019, and a $154,000$17,000 decrease related to the 3.5 MBblapproximately a 300 Bbl decrease in sales volumes.  The 3.5 MBbl300 Bbl decrease was primarily due to natural declines, partially offset by increased production on the Albers, Albers B, Coddington, Veverka B,D lease as a result of a polymer work performed in the second quarter 2018, and C leases,by increased production on the BSU #1-30 well which was completed in October 2018.

Comparison of the Quarters Ended March 31, 2019 and 2018

The Company reported a net loss from continuing operations of $(96,000) or $(0.01) per share of common stock during the first quarter of 2019 compared to a net income from continuing operations of $133,000 or $0.01 per share of common stock during the first quarter of 2018.  The $229,000 decrease in net income was primarily due to a $196,000 decrease in revenues, a $49,000 increase in production cost and taxes, partially offset by a $29,000 increase in gain on sale of assets.

The Company recognized $1.2 million in revenues during the first quarter of 2019 compared to $1.4 million during the first quarter of 2018. The $196,000 decrease in net revenue was primarily due to a $175,000 decrease related to an $7.48 per barrel decrease in the average oil price from $57.36 per barrel during the first three months of 2018 to $49.88 per barrel during the first three months of 2019, and a $17,000 decrease related to approximately a 300 Bbl decrease in sales volumes.  The 300 Bbl decrease was primarily due to natural declines, partially offset by increased production on the Veverka D lease as a result of a polymer performed in the 2ndsecond quarter 2018, and by increased production on the Nutsch-BussBSU #1-30 well as a result of work performed at the end of 2017.

Comparison of the Quarters Ended September 30, 2018 and 2017

The Company reported a net income from continuing operations of $298,000 or $0.03 per share of common stock during the third quarter of 2018 compared to a net loss from continuing operations of $(361,000) or $(0.03) per share of common stock during the third quarter of 2017.  The $659,000 increasewhich was completed in net income was primarily due to a $619,000 increase in revenues, a $45,000 decrease in production cost and taxes, and a $15,000 decrease in interest expense, partially offset by a $20,000 increase in general and administrative expense.

The Company recognized $1.65 million in revenues during the third quarter of 2018 compared to $1.04 million during the third quarter of 2017. The $619,000 increase in net revenue was primarily due to a $558,000 increase related to a $21.80 per barrel increase in the average oil price from $42.54 per barrel during the third quarter of 2017 to $64.34 per barrel during the third quarter of 2018, and a $61,000 increase related to the 1.4 MBbl increase in sales volumes.  The 1.4 MBbl increase was primarily due to increased production on the Veverka D lease as a result of a polymer performed in the 2nd quarter 2018, partially offset by natural declines and timing of crude pickup by the refineries.October 2018.

Production cost and taxes decreased $45,000increased $49,000 from $907,000$730,000 during the thirdfirst quarter of 20172019 to $862,000$779,000 during the thirdfirst quarter of 2018.  This decrease was primarily due to an $118,000 decrease related to an amendment to the 2016 Delaware franchise taxes recorded in the third quarter of 2017, a $32,000 decrease in accrued Delaware franchise taxes, partially offset by a $54,000$51,000 increase related to change in the oil inventory quarterly adjustments, $22,000a $20,000 increase in pumping charges primarily related to replacement of a company pumper with a contract pumper, and a $17,000 increase in chemical costs, and a $20,000 increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices.

General and administrative costs increased $20,000 from $268,000 during the third quarter of 2017 to $288,000 during the third quarter of 2018.  This increase was primarily related to an increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices.

Interest expense decreased $15,000 from $16,000 during the third quarter of 2017 to $1,000 during the third quarter of 2018.  This decrease was primarily related to recording interest in the third quarter of 2017 related to the amendment of the 2016 Delaware franchise taxes.

Comparison of the Nine Months Ended September 30, 2018 and 2017

The Company reported a net income from continuing operations of $530,000 or $0.05 per share of common stock during the first nine months of 2018 compared to a net loss from continuing operations of $(761,000) or $(0.08) per share of common stock during the first nine months of 2017.  The $1.3 million increase in net income was primarily due to a $1.1 million increase in revenues, a $93,000 decrease in production cost and taxes, a $59,000 decrease in DD&A, a $32,000 decrease in interest expense, and a $29,000 increase on gain from asset sales, partially offset by a $36,000 increase in general and administrative costs.

The Company recognized $4.5 million in revenues during the first nine months of 2018 compared to $3.4 million during the first nine months of 2017. The revenue increase from 2017 levels primarily due to a $1.3 million increase related to a $17.35 per barrel increase in the average oil price from $43.92 per barrel during the first nine months of 2017 to $61.27 per barrel during the first nine months of 2018, partially offset by a $154,000$38,000 decrease related to the 3.5 MBbl decrease in sales volumes.  The 3.5 MBbl decrease was primarily due to natural declines on the Albers, Albers B, Coddington, Veverka B, and C leases, partially offset by increased production on the Veverka D lease as a result of a polymer performed in the 2nd quarter 2018, and by increased production on the Nutsch-Buss well as a result of work performed at the end of 2017.

17

Production costs and taxes decreased $93,000 from $2.6 million during the first nine months of 2017 to $2.5 million during the first nine months of 2018.  This decrease was primarily due to a $124,000 change in the oil inventory adjustment, a $118,000 decrease related to an amendment to the 2016 Delaware franchise taxes recorded in the third quarter of 2017, partially offset by a $50,000 increase in well and equipment repair costs, a $42,000 increase in chemical costs, and a $37,000 increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices.

DD&A decreased $59,000 from $658,000 during the first nine months of 2017 to $599,000 during the first nine months of 2018.  This decrease was primarily due to a $34,000 decrease related to a lower oil depletion rate, and a $28,000 decrease related to a 3.5 MBbl decrease in oil sales volumes.

General and administrative costs increased $36,000 from $860,000 during the first nine months of 2017 to $896,000 during the first nine months of 2018.  This increase was primarily due to an increase in legal and accounting cost, and an increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices.

Interest expense decreased $32,000 from $36,000 during the first nine months of 2017 to $4,000 during the first nine months of 2018.  This decrease was primarily related to recording interest in the third quarter 2017 related to the amendment of the 2016 Delaware franchise taxes, and a reduction of interest on the Company’s credit facility.costs.

Gain on sale of assets increased $29,000 from $5,000$16,000 during the first nine monthsquarter of 20172018 to $34,000$45,000 during the first nine monthsquarter of 2018.2019.  This increase was primarily related to recording sale of equipment inventory to a third party during the first quarter of 2019, partially offset by recording gains on disposalsales of fieldcompany vehicles recorded during the first quarter of 2018.

Liquidity and Capital Resources

At September 30, 2018,March 31, 2019, the Company had a revolving credit facility with Prosperity Bank.  This has historically been 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 $50 million or the Company’s borrowing base in effect from time to time. As of September 30, 2018,March 31, 2019, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility includes certain covenants with which the Company is required to comply.  At September 30, 2018,March 31, 2019, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At September 30, 2018,March 31, 2019, the interest rate on this credit facility was 5.75%6.00%.  The Company was in compliance with all covenants during the quarter ended September 30, 2018.

On August 24, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.March 31, 2019.  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 5.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30,March 31, 2019 or December 31, 2018.  The next borrowing base review will take place in MarchMay 2019.

On March 21, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s review of the Company’s owned producing properties was amended to increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020.  The borrowing base remained subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.00% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30, 2018.  The next borrowing base review will take place in March 2019.

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility 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 $3.0 million borrowing base with no funds currently drawn. This borrowing base in subject to a credit limit of approximately $2.74 million.  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 byused in operating activities from continuing operations was $1.0 million$18,000 during the first ninethree months of 20182019 compared to $191,000$71,000 provided by operating activities from continuing operations during the first ninethree months of 2017.2018.  Cash flow used in working capital was $190,000$102,000 during the first ninethree months of 20182019 compared to $170,000 provided by$270,000 used in working capital during the first ninethree months of 2017.2018. The $360,000 increase$168,000 decrease in cash flow used in working capital was primarily due to changes in inventory, changes in accrued liabilities, and changes in accounts receivable, partially offset by changes in accounts payable.  The $827,000 increase$89,000 decrease in cash provided by operating activities was primarily due to a $1.1 million$196,000 decrease in revenues, and a $49,000 increase in revenues,production cost and taxes, partially offset by the $360,000 increase$168,000 decrease in cash flow used in working capital.  Net cash used inprovided by investing activities from continuing operations was $466,000$139,000 during the first ninethree months of 20182019 compared to $153,000$(41,000) used in investing activities from continuing operations during the first ninethree months of 2017.2018.  This increase in cash flow used inprovided by investing activities was primarily due to drilling and polymers performed in 2018.sale of materials inventory to a third party during the first three months of 2019.  Cash flow used in financing activities from continuing operations during the first ninethree months of 20182019 was $30,000$(12,000) compared to $153,000 provided by$(16,000) used in financing activities during the first ninethree months of 2017.  During the first nine months of 2017, the Company raised approximately $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 were incurred during 2016.  The net proceeds from this offering were used primarily to pay off the Company’s credit facility.2018.

18

Critical Accounting Policies

Effective January 1, 2018,2019, the Company adopted ASU 2014-092016-02 Revenue from Contracts with CustomersLeases (Topic 842).

Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“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 a preliminaryan 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 preliminary analysis raised issues other than the “Incident of Non-Compliance” discussed above.  The Company is discussing this preliminary 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.

In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties.  Since September 30, 2018, the Company has entered into a drilling and seismic commitments in the amount of approximately $131,000.  In addition, in the second quarter of 2018, the Company also entered into a seismic commitment in the amount of approximately $32,000.  Work associated with these commitments started in October 2018.  Finally, the Company started drilling a well in August 2018, however, at September 30, 2018 the well was still in the process of being completed.  The completion of this well occurred in October 2018 with a cost of approximately $69,000 being incurred after September 30, 2018.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions were to 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.  In May 2018, oil prices as so calculated exceeded $70 and compensation reverted 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 September 30, 2018,March 31, 2019, the reductions were approximately $445,000.$432,000.  Of the $432,000, approximately $103,000 will be paid in the Company’s common stock.  The $103,000 value represents approximately 100,000 common share valued at $1.03 per share which represents the closing price on March 29, 2019.  The Company has not accrued any liabilities associated with these compensation reductions.

Legal Proceedings

The Company is not a party to any pending material legal proceeding.   To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company.  To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.

19

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.

19

As of September 30, 2018,March 31, 2019, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2.74 million, of which zero had been drawn down by the Company.  The Company’s next periodic borrowing base review will take place in MarchMay 2019.

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 ninethree months of 20182019 ranged from a low of $56.66$46.39 per barrel to a high of $65.70$52.93 per barrel.

As of September 30, 2018,March 31, 2019, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At September 30, 2018,March 31, 2019, the Company had debtbalances on financing leases outstanding of approximately $136,000, none of which was$112,000, and no balance owed on its credit facility with Prosperity Bank.  As of September 30, 2018,March 31, 2019, the interest rate on the credit facility was variable at a rate equal to prime plus 0.50% per annum.  The Company’s credit facility interest rate at September 30, 2018March 31, 2019 was 5.75%6.00%.  The Company’s remaining debtfinancing leases of $136,000 has$112,000 have fixed interest rates ranging from 4.16%5.0% to 4.60%6.5%.

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 September 30, 2018.March 31, 2019.  The Company did not have any open derivative contracts relating to interest rates at September 30, 2018March 31, 2019 or December 31, 2017.2018.

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.

20

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 ninethree months ended September 30, 2018,March 31, 2019, there have been no changes to the Company’s system of internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.  As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

PART II OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

None.

ITEM 1A.
RISK FACTORS

Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 20172018 filed on March 28, 20182019 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.

21

ITEM 6.
EXHIBITS

The following exhibits are filed with this report:

Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a.
Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Calculation Linkbase Document
101.DEFXBRL Taxonomy Definition Linkbase Document
101.LABXBRL Taxonomy Label Linkbase Document
101.PREXBRL Taxonomy Presentation Linkbase Document

22

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:  NovemberMay 14, 20182019

TENGASCO, INC.

By:/s/Michael J. Rugen 
 Michael J. Rugen 
 Chief Executive Officer and Chief Financial Officer 


23