10-Q

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 March 31, 2017

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.)

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

(Address of principal executive offices)

720-420-4460

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, a non-accelerated filer, 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  ☒
(Do not check if a 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 ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,608,952 common shares at May 8, 2017.

TABLE OF CONTENTS

		PAGE
PART I.	FINANCIAL INFORMATION
	ITEM 1. FINANCIAL STATEMENTS
	*    Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	3
	*    Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016	5
	*    Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016	6
	*    Notes to Unaudited Condensed Consolidated Financial Statements	7
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	18
	ITEM 4. CONTROLS AND PROCEDURES	20
PART II.	OTHER INFORMATION	20
	ITEM 1. LEGAL PROCEEDINGS	20
	ITEM 1A. RISK FACTORS	20
	ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	21
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES	21
	ITEM 4. MINE SAFTY DISCLOSURES	21
	ITEM 5. OTHER INFORMATION	21
	ITEM 6. EXHIBITS	21
	*    SIGNATURES	22
	*    CERTIFICATIONS

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

	March 31, 2017		December 31, 2016
Assets
Current
Cash and cash equivalents	$	228	$	76
Accounts receivable, less allowance for doubtful accounts of $14		536		490
Accounts receivable – related party, less allowance for doubtful accounts of $159		—		—
Inventory		597		627
Other current assets		255		421
Total current assets		1,616		1,614
Loan fees, net		20		24
Oil and gas properties, net (full cost accounting method)		5,020		5,225
Manufactured Methane facilities, net		1,544		1,559
Other property and equipment, net		123		140
Total assets	$	8,323	$	8,562

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

3

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

	March 31, 2017			December 31, 2016
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable – trade	$	199		$	303
Accounts payable – other		159			159
Accrued and other current liabilities		216			274
Current maturities of long-term debt		53			55
Total current liabilities		627			791
Asset retirement obligation		2,071			2,046
Long term debt, less current maturities		34			2,447
Total liabilities		2,732			5,284
Commitments and contingencies (Note 13)
Stockholders’ equity
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $0.001 par value, 10,000 shares designated; 0 shares issued and outstanding		—			—
Common stock, $.001 par value, authorized 100,000,000 shares; 10,601,685 and 6,097,723 shares issued and outstanding		11			6
Additional paid–in capital		58,308			55,787
Accumulated deficit		(52,728	)		(52,515	)
Total stockholders’ equity		5,591			3,278
Total liabilities and stockholders’ equity	$	8,323		$	8,562

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

4

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands, except share and per share data)

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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands, except share data)

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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

6

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”) operates treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of March 31, 2017 and March 31, 2016 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2016 is derived from the audited financial statements, but does not include all disclosures required by U.S. GAAP.  The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01.  Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ended December 31, 2017. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Principles of Consolidation

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

Use of Estimates

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

Revenue Recognition

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.  There were no material natural gas imbalances at March 31, 2017 or December 31, 2016.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes.  No methane gas was sold during the three months ended March 31, 2017 or 2016.

Cash and Cash Equivalents

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

7

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Inventory

Inventory consists of crude oil in tanks and is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended March 31, 2017 and December 31, 2016.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The net realizable value component is calculated using the average March 2017 and December 2016 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or net realizable value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The net realizable value component is based on estimated sales value for similar equipment and materials as of March 31, 2017 and December 31, 2016.  The following table sets forth information concerning the Company’s inventory (in thousands):

	March 31, 2017			December 31, 2016
Oil – carried at net realizable value	$	475	$	505
Equipment and materials – carried at net realizable value		122		122
Total inventory	$	597	$	627

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities.  Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd.  The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had unevaluated properties of $48,000 and $106,000 at March 31, 2017 and December 31, 2016, respectively.  Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down cannot be reversed in a later period.  During the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at March 31, 2017 and December 31, 2016.

8

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

	March 31, 2017			December 31, 2016
Revenue	$	512		$	476
Joint interest		22			21
Other		16			7
Allowance for doubtful accounts		(14	)		(14	)
Total accounts receivable	$	536		$	490

Reclassifications

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

(2) Liquidity

During 2016, the Company incurred a net loss of approximately $4.2 million.  In addition as of December 31, 2016, as discussed in Note 8 Long-Term Debt, the Company was in default with various covenants included in its credit facility with Prosperity Bank.  Each of these defaults was cured either through a waiver or an amendment to its credit facility.  During 2017, the Company believes its revenues will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $1.25 million borrowing base with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

(3)  Income Taxes

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

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

The Company does not expect to pay any federal or state income tax for the year 2017 as a result of $26.4 million of net operating loss carry forwards that existed at December 31, 2016.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some or all of the benefits of deferred tax assets will not be realized.  As of March 31, 2017, the Company has recorded a full valuation allowance on its deferred tax assets primarily due to cumulated losses incurred during the 3 years ended December 31, 2016.  Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes.  There were no recorded unrecognized tax benefits at March 31, 2017.

(4) Capital Stock

Common Stock

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

On February 13, 2017, 4,498,698 common shares were issued to participants of the Company’s rights offering which closed on February 2, 2017.  Of the 4,498,698 common shares issued, 3,293,407 were issued to the Company’s directors, management, and affiliates.  The Company received approximately $2.7 million in gross proceeds from this rights offering.  The direct costs associated with this rights offering was approximately $177,000.

9

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Rights Agreement

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

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

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

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

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

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

Preferred Stock

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

10

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(5)  Earnings per Common Share

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

	For the Three Months Ended March 31,
	2017			2016
Income (numerator):
Net loss	$	(213	)	$	(1,404	)
Weighted average shares (denominator):
Weighted average shares – basic		8,452,132			6,084,241
Dilution effect of share-based compensation, treasury method		—			—
Weighted average shares – dilutive		8,452,132			6,084,241
Loss per share – Basic and Dilutive:
Basic and Dilutive	$	(0.03	)	$	(0.23	)

(6)  Recent Accounting Pronouncements

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

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

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

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

11

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

In August 2016, the FASB issued Update 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.  This amendment provides guidance on certain cash flow classification issues, thereby reducing the current and potential future diversity in practice. This guidance iseffective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period.  The Company does not expect this to impact operating results or cash flows.

 (7)  Related Party Transactions

On September 17, 2007, Hoactzin Partners, L.P. (“Hoactzin”) subscribed to a drilling program offered by the Company consisting of wells to be drilled on the Company’s Kansas Properties (the “Program”).  Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin and of Dolphin Offshore Partners, L.P., the Company’s largest shareholder.  Hoactzin was also conveyed a net profits interest in the MMC facility at the Carter Valley municipal solid waste landfill owned and operated by Republic Services, Inc. in Church Hill, Tennessee where the Company installed a propriety combination of advanced gas treatment technology to extract the methane component of the purchased gas stream (the “Methane Project”).  The net profits interest owned by Hoactzin is now 7.5% of the net profits as defined by agreement and takes into account specific costs and expenses as well as gross gas revenues for the project.  As a result of the startup costs, monthly operating expenses, and gas production levels experienced, no net profits as defined were realized during the period from the project startup in April, 2009 through March 31, 2017 for payment to Hoactzin under the net profits interest.  Since the start of 2014, there have been no methane gas sales or revenues, and consequently no net profits attributable to Hoactzin’s net profits interest.

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement.  The Management Agreement expired on December 18, 2012.

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

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

As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties.  In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name.  As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet.  Payables related to these past due and ongoing operations remained outstanding at March 31, 2017 and December 31, 2016 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of March 31, 2017 and December 31, 2016 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at March 31, 2017 and December 31, 2016.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at March 31, 2017 and December 31, 2016.

12

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(8)  Oil and Gas Properties

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

	March 31, 2017			December 31, 2016
Oil and gas properties	$	5,373		$	5,315
Unevaluated properties		48			106
Accumulated depreciation, depletion, and amortization		(401	)		(196	)
Oil and gas properties	$	5,020		$	5,225

The Company recorded depletion expense of $204,000 and $302,000 for the three months ended March 31, 2017 and 2016, respectively.  During the three months ended March 31, 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $1,000 gain on asset retirement obligations.  In addition, during the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.  As a result of the ceiling test impairments during 2015 and the first three quarters of 2016, the accumulated depreciation, depletion, and amortization was been netted against the cost to reflect the post impairment value of the oil and gas properties.  As no ceiling test impairment was recorded during the quarters ended December 31, 2016 and March 31, 2107, this amount was not netted against cost, but remained in accumulated depreciation, depletion, and amortization at December 31, 2016 and March 31, 2017.

(9)  Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the three months ended March 31, 2017 (in thousands):

Balance December 31, 2016	$	2,046
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(11	)
Balance March 31, 2017	$	2,071

(10)  Long-Term Debt

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

	March 31, 2017			December 31, 2016
Note payable to a financial institution, with interest only payment until maturity	$	—		$	2,400
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		87			102
Total debt		87			2,502
Less current maturities		(53	)		(55	)
Long-term debt, less current maturities	$	34		$	2,447

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

13

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

At March 31, 2017, the Company had a revolving credit facility with Prosperity Bank.  This is the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of March 31, 2017, the Company’s borrowing base was $1.25 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio.  During the quarter ended March 31, 2017, the Company was in compliance with all covenants.

Effective March 16, 2017, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended and restated to among other things, decrease the Company’s borrowing base from $3.0 million to approximately $1.25 million, and extend the term of the facility to July 31, 2018.  In addition, all the covenants were removed and replaced with the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA Ratio < 3.5x; and (c) Interest Coverage Ratio > 3.0x.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 4.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million and the Company had no outstanding borrowing under the facility as of March 31, 2017.

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

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

(11)  Manufactured Methane

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

	March 31, 2017			December 31, 2016
Manufactured Methane facilities, at cost	$	1,681		$	1,681
Accumulated depreciation		(137	)		(122	)
Manufactured Methane facilities, net	$	1,544		$	1,559

The Manufactured Methane facilities were placed into service on April 1, 2009.  The Manufactured Methane facilities are being depreciated over a remaining estimated useful life of approximately 25 years based on estimated landfill closure date of December 2041.  The Company recorded depreciation expense of $15,000 for the three months ended March 31, 2017 and 2016.

(12)  Fair Value Measurements

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

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

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

14

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of March 31, 2017 and December 31, 2016.

(13)  Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties.  This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction.  The Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility.  In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.  The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.

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

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2017, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  The Company has not accrued any liabilities associated with these compensation reductions.

15

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

Results of Operations and Financial Condition

During the first three months of 2017, 33.5 MBbl gross of oil were sold from the Company’s properties.  Of the 33.5 MBbl sold, 26.0 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 three months of 2017 of 26.0 MBbl of oil compares to net sales of 27.8 MBbl of oil during the first three months of 2016.  The Company’s net revenue from its oil and gas properties was $1.2 million during the first three months of 2017 compared to $782,000 during the first three months of 2016.  This increase in net revenue was primarily due to a $484,000 increase related to an $18.65 per barrel increase in the average oil price from $27.67 per barrel during the first three months of 2016 to $46.32 per barrel during the first three months of 2017, partially offset by a $52,000 decrease related to the 1.8 MBbl decrease in sales volumes.  The 1.8 MBbl decrease was primarily due to decreased sales volumes from the Albers A, Albers B, Liebenau, and Veverka A leases.  MMC revenues during the first three months of 2017 and 2016 were $135,000 and $150,000, respectively.

Comparison of the Quarters Ended March 31, 2017 and 2016

The Company reported a net loss of $213,000 or $0.03 per share of common stock during the first quarter of 2017 compared to a net loss of $1.4 million or $0.23 per share of common stock during the first quarter of 2016.  The $1.2 million decrease in net loss was primarily due to a ceiling test impairment of $641,000 recorded in the first quarter of 2016 as a result of the low oil prices experienced during 2015 and 2016, a $412,000 increase in revenues, a $166,000 decrease in general and administrative costs, and a $100,000 decrease in DD&A, partially offset by a $132,000 increase in production cost and taxes.

The Company recognized $1.3 million in revenues during the first quarter of 2017 compared to $932,000 during the first quarter of 2016. The revenue increase from 2016 levels was primarily due to a $484,000 increase related to a $18.65 per barrel increase in the average oil price from an average price of $27.67 per barrel during first quarter of 2016 compared to an average price of $46.32 per barrel during the first quarter of 2017, partially offset by a $52,000 decrease related to a 1.8 MBbl decrease in sales volumes, primarily from the Albers A, Albers B, Liebenau, and Veverka A leases.  In addition, there was a $15,000 decrease in methane facility revenues related to lower runtimes.

Production cost and taxes increased $132,000 from $839,000 during the first quarter of 2016 to $971,000 during the first quarter of 2017.  This increase was primarily due to a $105,000 increase in methane facility costs, and a $70,000 change in the oil inventory quarterly adjustment, partially offset by a $20,000 decrease in Kansas property tax costs.

DD&A decreased $100,000 from $336,000 during the first quarter of 2016 to $236,000 during the first quarter of 2017.  This decrease was primarily due to a $78,000 decrease related to a lower oil depletion rate as a result of impairments in 2016, and a $20,000 decrease related to a 1.8 MBbl decrease in oil sales volumes.

General and administrative costs decreased $166,000 from $500,000 during the first quarter of 2016 to $334,000 during the first quarter of 2017.  This decrease was primarily due to an $112,000 decrease in corporate payroll costs as a result of personnel reductions during the first quarter 2016, an $18,000 reduction of stock transfer and proxy costs primarily as a result of the reverse stock split which occurred in the first quarter of 2016, and a $16,000 reduction in legal and accounting cost.

Liquidity and Capital Resources

At March 31, 2017, the Company had a revolving credit facility with Prosperity Bank.  This is the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of March 31, 2017, the Company’s borrowing base was $1.25 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio.  During the quarter ended March 31, 2017, the Company was in compliance with all covenants.

Effective March 16, 2017, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended and restated to among other things, decrease the Company’s borrowing base from $3.0 million to approximately $1.25 million, and extend the term of the facility to July 31, 2018.  In addition, all the covenants were removed and replaced with the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA Ratio < 3.5x; and (c) Interest Coverage Ratio > 3.0x.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 4.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million and the Company had no outstanding borrowing under the facility as of March 31, 2017.

16

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

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

During 2016, the Company incurred a net loss of approximately $4.2 million.  In addition as of December 31, 2016, the Company was in default with various covenants included in its credit facility with Prosperity Bank.  Each of these defaults was cured either through a waiver or an amendment to its credit facility.  During 2017, the Company believes its revenues will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $1.25 million borrowing base with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

Net cash used in operating activities decreased $1.0 million from $1.1 million used in operating activities during the first three months of 2016 to $88,000 used in operating activities during the first three months of 2017.  Cash flow used in working capital was $155,000 during the first three months of 2017 compared to $683,000 used in working capital during the first three months of 2016. The $528,000 reduction in cash flow used in working capital was primarily due to a $634,000 payment of suspended Hoactzin drilling program payments that was paid in January 2016.  The $1.0 million decrease in cash flow used in operating activities was primarily due to a $528,000 decrease in cash flow used in working capital, a $412,000 increase in revenues, and a $166,000 decrease in general and administrative costs, partially offset by a $132,000 increase in production cost and taxes.  Net cash used in investing activities was $7,000 during the first three months of 2017 compared to $301,000 used in investing activities during the first three months of 2016.  The $294,000 decrease in net cash used in investing activities was primarily a result of a $252,000 reduction in drilling, seismic, and leasehold cost during the first three months of 2017 compared to the first three months of 2016.  Cash flow provided by financing activities during the first three months of 2017 was $247,000 compared to $1.4 million provided by financing activities during the first three months of 2016.  During the first three months of 2017, the Company raised $2.7 million in proceeds as a result of a rights offering which closed on February 2, 2017.  The direct costs associated with this rights offering was approximately $177,000, of which $140,000 was incurred during 2016.  The net proceeds from this offering were used primarily to pay off the Company’s credit facility.

Critical Accounting Policies

During the three months ended March 31, 2017, there were no changes to the critical accounting policies included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties.  This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction.  The Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility.  In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.  The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.

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

17

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2017, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  For the period January 1, 2015 through March 31, 2017, the reductions were approximately $286,000.  The Company has not accrued any liabilities associated with these compensation reductions.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

The borrowing base under the Company’s revolving credit facility will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves.  If cash flow from operations or the Company’s borrowing base decreases for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected.  As a result, the Company’s ability to replace naturally declining production may be limited. In addition, if the borrowing base is reduced, the Company may be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility.

As of March 31, 2017, the Company’s borrowing base was approximately $1.25 million of which zero had been drawn down by the Company.  The Company’s next periodic borrowing base review will take place in July 2017.

Commodity Risk

The Company's major market risk exposure is in the pricing applicable to its oil production.  Realized pricing is primarily driven by the prevailing worldwide price for crude oil.  Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.  The average monthly Kansas oil prices received during the first three months of 2017 ranged from a low of $44.13 per barrel to a high of $47.49 per barrel.

As of March 31, 2017, the Company has no open positions related to derivative agreements relating to commodities.

Interest Rate Risk

At March 31, 2017, the Company had debt outstanding of approximately $87,000, none of which was owed on its credit facility with Prosperity Bank. As of March 31, 2017, the interest rate on the credit facility was variable at a rate equal to prime plus 0.50% per annum.  The Company’s credit facility interest rate at March 31, 2017 was 4.50%.  The Company’s remaining debt of $87,000 has fixed interest rates ranging from 4.16% to 4.60%.

The annual impact on interest expense and the Company’s cash flows of a 10% increase in the interest rate on the credit facility would be approximately zero assuming borrowed amounts under the credit facility remained at the same amount owed as of March 31, 2017.  The Company did not have any open derivative contracts relating to interest rates at March 31, 2017 or December 31, 2016.

18

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.

19

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 three months ended March 31, 2017, there have been no changes to the Company’s system of internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.  As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

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

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

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

ITEM 1A. RISK FACTORS

Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 2016 filed on March 30, 2017 which is incorporated by this reference.

20

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The following exhibits are filed with this report:

31	Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a.
32	Certification of the Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C Section 1350 as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Calculation Linkbase Document
101.DEF	XBRL Taxonomy Definition Linkbase Document
101.LAB	XBRL Taxonomy Label Linkbase Document
101.PRE	XBRL Taxonomy Presentation Linkbase Document

21

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:	May 12, 2017
TENGASCO, INC.
By:	/s/Michael J. Rugen
	Michael J. Rugen
	Chief Executive Officer and Chief Financial Officer

22

EX-31

Exhibit 31   CERTIFICATION

I, Michael J. Rugen, certify that:

1.   I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended March 31, 2017.

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s certifying officers are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f) for the registrant and we have:

(a)   designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The Registrant’s certifying officers have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: May 12, 2017
By:	/s/ Michael J. Rugen
	Michael J. Rugen
	Chief Executive Officer and Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

To the best of my knowledge this Quarterly Report on Form 10-Q (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly present, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

Dated:  May 12, 2017
	By:	/s/ Michael J. Rugen
		Michael J. Rugen
		Chief Executive Officer and Chief Financial Officer

XML

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

XML

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

XML

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

XML

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

XML

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

XML

Description Of Business And Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Description Of Business And Significant Accounting Policies [Abstract]

Description Of Business And Significant Accounting Policies

(1)  Description of Business and Significant Accounting Policies

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

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

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

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of March 31, 2017 and March 31, 2016 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2016 is derived from the audited financial statements, but does not include all disclosures required by U.S. GAAP.  The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01.  Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ended December 31, 2017. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Principles of Consolidation

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

Use of Estimates

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

Revenue Recognition

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.  There were no material natural gas imbalances at March 31, 2017 or December 31, 2016.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes.  No methane gas was sold during the three months ended March 31, 2017 or 2016.

Cash and Cash Equivalents

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

Inventory

Inventory consists of crude oil in tanks and is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended March 31, 2017 and December 31, 2016.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The net realizable value component is calculated using the average March 2017 and December 2016 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or net realizable value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The net realizable value component is based on estimated sales value for similar equipment and materials as of March 31, 2017 and December 31, 2016.  The following table sets forth information concerning the Company’s inventory (in thousands):

	March 31,		December 31,
	2017		2016
Oil – carried at net realizable value	$	475	$	505
Equipment and materials – carried at net realizable value		122		122
Total inventory	$	597	$	627

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities.  Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd.  The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had unevaluated properties of $48,000 and $106,000 at March 31, 2017 and December 31, 2016, respectively.  Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down cannot be reversed in a later period.  During the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at March 31, 2017 and December 31, 2016.

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

	March 31,		December 31,
	2017		2016
Revenue	$	512	$	476
Joint interest		22		21
Other		16		7
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	536	$	490

Reclassifications

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

XML

Liquidity

3 Months Ended

Mar. 31, 2017

Liquidity [Abstract]

Liquidity

(2) Liquidity

During 2016, the Company incurred a net loss of approximately $4.2 million.  In addition as of December 31, 2016, as discussed in Note 8 Long-Term Debt, the Company was in default with various covenants included in its credit facility with Prosperity Bank.  Each of these defaults was cured either through a waiver or an amendment to its credit facility.  During 2017, the Company believes its revenues will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $1.25 million borrowing base with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

XML

Income Taxes

3 Months Ended

Mar. 31, 2017

Income Taxes [Abstract]

Income Taxes

(3)  Income Taxes

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

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

The Company does not expect to pay any federal or state income tax for the year 2017 as a result of $26.4 million of net operating loss carry forwards that existed at December 31, 2016.  Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some or all of the benefits of deferred tax assets will not be realized.  As of March 31, 2017, the Company has recorded a full valuation allowance on its deferred tax assetsprimarily due to cumulated losses incurred during the 3 years ended December 31, 2016.  Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes.  There were no recorded unrecognized tax benefits at March 31, 2017.

XML

Capital Stock

3 Months Ended

Mar. 31, 2017

Stockholders' equity

Capital Stock

(4) Capital Stock

Common Stock

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

On February 13, 2017, 4,498,698 common shares were issued to participants of the Company’s rights offering which closed on February 2, 2017.  Of the 4,498,698 common shares issued, 3,293,407 were issued to the Company’s directors, management, and affiliates.  The Company received approximately $2.7 million in gross proceeds from this rights offering.  The direct costs associated with this rights offering was approximately $177,000.

Rights Agreement

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

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

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

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

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

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

Preferred Stock

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

XML

Earnings Per Common Share

3 Months Ended

Mar. 31, 2017

Earnings Per Common Share [Abstract]

Earnings Per Common Share

(5)  Earnings per Common Share

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

	For the Three Months Ended
	March 31,
	2017		2016
Income (numerator):
Net loss	$	(213)	$	(1,404)
Weighted average shares (denominator):
Weighted average shares – basic		8,452,132		6,084,241
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares – dilutive		8,452,132		6,084,241
Loss per share – Basic and Dilutive:
Basic and Dilutive	$	(0.03)	$	(0.23)

XML

Recent Accounting Pronouncements

3 Months Ended

Mar. 31, 2017

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

(6)  Recent Accounting Pronouncements

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

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

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

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

In August 2016, the FASB issued Update 2016-15 Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.  This amendment provides guidance on certain cash flow classification issues, thereby reducing the current and potential future diversity in practice.  This guidance iseffective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period.  The Company does not expect this to impact operating results or cash flows.

XML

Related Party Transactions

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

 (7)  Related Party Transactions

On September 17, 2007, Hoactzin Partners, L.P. (“Hoactzin”) subscribed to a drilling program offered by the Company consisting of wells to be drilled on the Company’s Kansas Properties (the “Program”).  Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin and of Dolphin Offshore Partners, L.P., the Company’s largest shareholder.  Hoactzin was also conveyed a net profits interest in the MMC facility at the Carter Valley municipal solid waste landfill owned and operated by Republic Services, Inc. in Church Hill, Tennessee where the Company installed a propriety combination of advanced gas treatment technology to extract the methane component of the purchased gas stream (the “Methane Project”).  The net profits interest owned by Hoactzin is now 7.5% of the net profits as defined by agreement and takes into account specific costs and expenses as well as gross gas revenues for the project.  As a result of the startup costs, monthly operating expenses, and gas production levels experienced, no net profits as defined were realized during the period from the project startup in April, 2009 through March 31, 2017 for payment to Hoactzin under the net profits interest.  Since the start of 2014, there have been no methane gas sales or revenues, and consequently no net profits attributable to Hoactzin’s net profits interest. 

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement.  The Management Agreement expired on December 18, 2012. 

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

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

As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties.  In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name.  As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet.  Payables related to these past due and ongoing operations remained outstanding at March 31, 2017 and December 31, 2016 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of March 31, 2017 and December 31, 2016 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at March 31, 2017 and December 31, 2016.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at March 31, 2017 and December 31, 2016.

XML

Oil And Gas Properties

3 Months Ended

Mar. 31, 2017

Oil And Gas Properties [Abstract]

Oil And Gas Properties

(8)  Oil and Gas Properties

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

	March 31,		December 31,
	2017		2016
Oil and gas properties	$	5,373	$	5,315
Unevaluated properties		48		106
Accumulated depreciation, depletion, and amortization		(401)		(196)
Oil and gas properties	$	5,020	$	5,225

The Company recorded depletion expense of $204,000 and $302,000 for the three months ended March 31, 2017 and 2016, respectively.  During the three months ended March 31, 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $1,000 gain on asset retirement obligations.  In addition, during the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.  As a result of the ceiling test impairments during 2015 and the first three quarters of 2016, the accumulated depreciation, depletion, and amortization was been netted against the cost to reflect the post impairment value of the oil and gas properties.  As no ceiling test impairment was recorded during the quarters ended December 31, 2016 and March 31, 2107, this amount was not netted against cost, but remained in accumulated depreciation, depletion, and amortization at December 31, 2016 and March 31, 2017.

XML

Asset Retirement Obligation

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

(9)  Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the three months ended March 31, 2017(in thousands):

Balance December 31, 2016	$	2,046
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(11)
Balance March 31, 2017	$	2,071

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2017

Long-Term Debt [Abstract]

Long-Term Debt

(10)  Long-Term Debt

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

	March 31,		December 31,
	2017		2016
Note payable to a financial institution, with interest only payment until maturity	$	—	$	2,400
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		87		102
Total debt		87		2,502
Less current maturities		(53)		(55)
Long-term debt, less current maturities	$	34	$	2,447

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

At March 31, 2017, the Company had a revolving credit facility with Prosperity Bank.  This is the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of March 31, 2017, the Company’s borrowing base was $1.25 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2017, these covenants included a current ratio, a funded debt to EBITDA ratio, and an interest coverage ratio.  During the quarter ended March 31, 2017, the Company was in compliance with all covenants.

Effective March 16, 2017, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended and restated to among other things, decrease the Company’s borrowing base from $3.0 million to approximately $1.25 million, and extend the term of the facility to July 31, 2018.  In addition, all the covenants were removed and replaced with the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA Ratio < 3.5x; and (c) Interest Coverage Ratio > 3.0x.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 4.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million and the Company had no outstanding borrowing under the facility as of March 31, 2017. 

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

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

XML

Manufactured Methane

3 Months Ended

Mar. 31, 2017

Manufactured Methane [Abstract]

Manufactured Methane

(11)  Manufactured Methane

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

	March 31,		December 31,
	2017		2016
Manufactured Methane facilities, at cost	$	1,681	$	1,681
Accumulated depreciation		(137)		(122)
Manufactured Methane facilities, net	$	1,544	$	1,559

The Manufactured Methane facilities were placed into service on April 1, 2009.  The Manufactured Methane facilities are being depreciated over a remaining estimated useful life of approximately 25 years based on estimated landfill closure date of December 2041.  The Company recorded depreciation expense of $15,000for the three months ended March 31, 2017 and 2016.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Measurements [Abstract]

Fair Value Measurements

(12)  Fair Value Measurements

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

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

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

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

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

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

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of March 31, 2017 and December 31, 2016.

XML

Commitments And Contingencies

3 Months Ended

Mar. 31, 2017

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(13)  Commitments and Contingencies

The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties.  This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011.  On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction.  The Company did not further appeal.  In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility.  In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.  The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.

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

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2017, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  The Company has not accrued any liabilities associated with these compensation reductions.

XML

Description Of Business And Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2017

Description Of Business And Significant Accounting Policies [Abstract]

Basis Of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of March 31, 2017 and March 31, 2016 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2016 is derived from the audited financial statements, but does not include all disclosures required by U.S. GAAP.  The Company believes that the disclosures made are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01.  Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ended December 31, 2017. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

Principles Of Consolidation

Principles of Consolidation

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

Use Of Estimates

Use of Estimates

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

Revenue Recognition

Revenue Recognition

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured.Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.  There were no material natural gas imbalances at March 31, 2017 or December 31, 2016.  Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes.  No methane gas was sold during the three months ended March 31, 2017 or 2016.

Cash And Cash Equivalents

Cash and Cash Equivalents

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

Inventory

Inventory

Inventory consists of crude oil in tanks and is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended March 31, 2017 and December 31, 2016.  These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost.  The net realizable value component is calculated using the average March 2017 and December 2016 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or net realizable value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The net realizable value component is based on estimated sales value for similar equipment and materials as of March 31, 2017 and December 31, 2016.  The following table sets forth information concerning the Company’s inventory (in thousands):

	March 31,		December 31,
	2017		2016
Oil – carried at net realizable value	$	475	$	505
Equipment and materials – carried at net realizable value		122		122
Total inventory	$	597	$	627

Full Cost Method Of Accounting

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities.  Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd.  The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had unevaluated properties of $48,000 and $106,000 at March 31, 2017 and December 31, 2016, respectively.  Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down cannot be reversed in a later period.  During the three months ended March 31, 2016, the Company recorded an impairment of oil and gas properties in the amount of $641,000, but recorded no impairment for the three months ended March 31, 2017.

Accounts Receivable

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at March 31, 2017 and December 31, 2016.

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

	March 31,		December 31,
	2017		2016
Revenue	$	512	$	476
Joint interest		22		21
Other		16		7
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	536	$	490

Reclassifications

Reclassifications

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

XML

Description Of Business And Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Description Of Business And Significant Accounting Policies [Abstract]

Inventory

	March 31,		December 31,
	2017		2016
Oil – carried at net realizable value	$	475	$	505
Equipment and materials – carried at net realizable value		122		122
Total inventory	$	597	$	627

Accounts Receivable

	March 31,		December 31,
	2017		2016
Revenue	$	512	$	476
Joint interest		22		21
Other		16		7
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	536	$	490

XML

Earnings Per Common Share (Tables)

3 Months Ended

Mar. 31, 2017

Earnings Per Common Share [Abstract]

Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share

	For the Three Months Ended
	March 31,
	2017		2016
Income (numerator):
Net loss	$	(213)	$	(1,404)
Weighted average shares (denominator):
Weighted average shares – basic		8,452,132		6,084,241
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares – dilutive		8,452,132		6,084,241
Loss per share – Basic and Dilutive:
Basic and Dilutive	$	(0.03)	$	(0.23)

XML

Oil And Gas Properties (Tables)

3 Months Ended

Mar. 31, 2017

Oil And Gas Properties [Abstract]

Schedule Of Oil And Gas Properties

	March 31,		December 31,
	2017		2016
Oil and gas properties	$	5,373	$	5,315
Unevaluated properties		48		106
Accumulated depreciation, depletion, and amortization		(401)		(196)
Oil and gas properties	$	5,020	$	5,225

XML

Asset Retirement Obligation (Tables)

3 Months Ended

Mar. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Transactions

Balance December 31, 2016	$	2,046
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(11)
Balance March 31, 2017	$	2,071

XML

Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

Long-Term Debt [Abstract]

Schedule Of Long-Term Debt To Unrelated Entities

	March 31,		December 31,
	2017		2016
Note payable to a financial institution, with interest only payment until maturity	$	—	$	2,400
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		87		102
Total debt		87		2,502
Less current maturities		(53)		(55)
Long-term debt, less current maturities	$	34	$	2,447

XML

Manufactured Methane (Tables)

3 Months Ended

Mar. 31, 2017

Manufactured Methane [Abstract]

Methane Facilities

	March 31,		December 31,
	2017		2016
Manufactured Methane facilities, at cost	$	1,681	$	1,681
Accumulated depreciation		(137)		(122)
Manufactured Methane facilities, net	$	1,544	$	1,559

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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