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, 2018

Commission File No. 1-15555

Tengasco, Inc.

(Exact name of registrant as specified in its charter)

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

8000 E. Maplewood Ave, Suite 130, Greenwood Village, CO 80111

(Address of principal executive offices)

720-420-4460

(Registrant’s telephone number, including area code)

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

Indicate by checkmark whether the registrant has submitted electronically 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: 10,624,493 common shares at May 7, 2018.

TABLE OF CONTENTS

		PAGE
PART I.	FINANCIAL INFORMATION
	ITEM 1. FINANCIAL STATEMENTS
	*    Unaudited Condensed Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017	3
	*    Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017	5
	*    Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017	6
	*    Notes to Unaudited Condensed Consolidated Financial Statements	7
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	17
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19
	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	20
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES	20
	ITEM 4. MINE SAFTY DISCLOSURES	20
	ITEM 5. OTHER INFORMATION	20
	ITEM 6. EXHIBITS	21
	*    SIGNATURES	22
	*    CERTIFICATIONS

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

	March 31, 2018		December 31, 2017
Assets
Current
Cash and cash equivalents	$	2,916	$	185
Accounts receivable, less allowance for doubtful accounts of $14		550		517
Accounts receivable – related party, less allowance for doubtful accounts of $159		—		—
Inventory		656		541
Other current assets		219		134
Discontinued operations included in current assets		—		121
Total current assets		4,341		1,498
Loan fees, net		12		13
Oil and gas properties, net (full cost accounting method)		4,570		4,720
Other property and equipment, net		243		135
Deferred tax asset		242		242
Discontinued operations included in non-current assets		—		1,497
Total assets	$	9,408	$	8,105

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, 2018			December 31, 2017
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable – trade	$	133		$	181
Accounts payable – other		159			159
Accrued and other current liabilities		211			187
Current maturities of long-term debt		56			41
Discontinued operations included in current liabilities		32			43
Total current liabilities		591			611
Asset retirement obligation		2,292			2,270
Long term debt, less current maturities		103			49
Total liabilities		2,986			2,930
Commitments and contingencies (Note 13)
Stockholders’ equity
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $.0001 par value, 10,000 shares designated; 0 shares issued and outstanding		—			—
Common stock, $.001 par value, authorized 100,000,000 shares; 10,624,493 and 10,619,924 shares issued and outstanding		11			11
Additional paid–in capital		58,257			58,253
Accumulated deficit		(51,846	)		(53,089	)
Total stockholders’ equity		6,422			5,175
Total liabilities and stockholders’ equity	$	9,408		$	8,105

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,
	2018			2017
Revenues
Oil and gas properties	$	1,367		$	1,209
Total revenues		1,367			1,209
Cost and expenses
Production costs and taxes		730			808
Depreciation, depletion, and amortization		183			221
General and administrative		336			334
Impairment		—			—
Total cost and expenses		1,249			1,363
Net income (loss) from operations		118			(154	)
Other expense
Net interest expense		(1	)		(16	)
Gain on sale of assets		16			—
Total other expenses		15			(16	)
Income (loss) from continuing operations before income tax		133			(170	)
Deferred income tax benefit		—			—
Net income (loss) from continuing operations		133			(170	)
Net income (loss) from discontinued operations		1,110			(43	)
Net income (loss)	$	1,243		$	(213	)
Net income (loss) per share - Basic and Fully Diluted
Continuing operations	$	0.01		$	(0.02	)
Discontinued operations	$	0.10		$	(0.01	)
Shares used in computing earnings per share
Basic and fully diluted		10,624,442			8,452,132

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

5

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands)

	For the Three Months Ended March 31,
	2018			2017
Operating activities
Net income (loss) from continuing operations	$	133		$	(170	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization		183			221
Amortization of loan fees-interest expense		1			4
Accretion on asset retirement obligation		36			36
(Gain) loss on asset sales		(16	)		—
Stock based compensation		4			4
Changes in assets and liabilities:
Accounts receivable		(33	)		44
Inventory and other assets		(200	)		56
Accounts payable		(48	)		(63	)
Accrued and other current liabilities		18			(50	)
Settlement on asset retirement obligation		(7	)		(10	)
Net cash provided by operating activities - continuing operations		71			72
Net cash provided by (used in) operating activities - discontinued operations		67			(160	)
Net cash provided by (used in) operating activities		138			(88	)
Investing activities
Additions to oil and gas properties		(32	)		(7	)
Proceeds from sale of oil and gas properties		3			—
Additions to other property and equipment		(19	)		—
Proceeds from sale of other property and equipment		7			—
Net cash used in investing activities - continuing operations		(41	)		(7	)
Net cash provided by investing activities - discontinued operations		2,650			—
Net cash provided by (used in) investing activities		2,609			(7	)
Financing activities
Repayments of borrowings		(116	)		(2,815	)
Proceeds from borrowings		100			400
Proceeds from stock issuance in rights offering		—			2,699
Costs of stock issuance in rights offering		—			(37	)
Net cash provided by (used in) financing activities - continuing operations		(16	)		247
Net cash provided by (used in) financing activities - discontinued operations		—			—
Net cash provided by financing activities		(16	)		247
Net change in cash and cash equivalents		2,731			152
Cash and cash equivalents, beginning of period		185			76
Cash and cash equivalents, end of period	$	2,916		$	228
Supplemental cash flow information:
Cash interest payments	$	—		$	12
Supplemental non-cash investing and financing activities:
Financed company vehicles	$	109		$	—
Costs of stock issuance in rights offering	$	—		$	(140	)
Capital expenditures included in accounts payable and accrued liabilities	$	6		$	—

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”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018 for $2.65 million. (See Note 11. Discontinued Operations)

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of March 31, 2018 and March 31, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2017 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, 2018 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Principles of Consolidation

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

Use of Estimates

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

Revenue Recognition

Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers.  The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

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

7

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

	Three Months Ended
	March 31, 2018		March 31, 2017
Revenues (in thousands):
Crude oil	$	1,357	$	1,203
Salt water disposal fees		10		6
Total	$	1,367	$	1,209

There were no natural gas imbalances at March 31, 2018 or December 31, 2017.

Cash and Cash Equivalents

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

Inventory

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

	March 31, 2018		December 31, 2017
Oil – carried at cost	$	551	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	656	$	541

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities.  Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had $0 in unevaluated properties as of March 31, 2018 and December 31, 2017.  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.

8

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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, 2018 and December 31, 2017.

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

	March 31, 2018			December 31, 2017
Revenue	$	519		$	479
Joint interest		23			23
Other		22			29
Allowance for doubtful accounts		(14	)		(14	)
Total accounts receivable	$	550		$	517

Reclassifications

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

(2) Liquidity

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $2.0 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

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

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

9

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

At December 31, 2017, federal net operating loss carryforwards amounted to approximately $30.2 million which expire between 2019 and 2036. The net total deferred tax asset was $242,000 at March 31, 2018 and December 31, 2017.  In 2017, The Company released a portion of the allowance related to the Company’s Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act.  The Company recorded an allowance on the remaining deferred tax asset at March 31, 2018 and December 31, 2017 primarily due to cumulative losses incurred during the 3 years ended December 31, 2017.  The Company expects to utilize its net operating losses and reduce its valuation allowance to offset taxable income resulting from the sale of the methane facility assets. There were no recorded unrecognized tax benefits at March 31, 2018.

(4) Capital Stock

Common Stock

On January 2, 2018, 4,569 common shares were issued in the aggregate to the Company’s four directors and CFO and interim CEO.

Rights Agreement

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

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

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

The Rights will expire prior to the earlier of March 16, 2020; or a date the Board of Directors determines by resolution in its business judgment that the Agreement is no longer necessary or appropriate; or in certain other specified circumstances.

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

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

Preferred Stock

Series A Preferred Stock has a par value of $0.0001 and 10,000 shares have been designated.  No shares of Series A Preferred Stock have been issued by the Company pursuant to the Rights Agreement described above or otherwise.

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,
	2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	133	$	(170	)
Net income (loss) from discontinued operations	$	1,110	$	(43	)
Weighted average shares (denominator):
Weighted average shares – basic		10,624,442		8,452,132
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares – dilutive		10,624,442		8,452,132
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.01	$	(0.02	)
Discontinued operations	$	0.10	$	(0.01	)

Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter were excluded from diluted shares.

(6) Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09 Revenue from Contracts with Customers (“ASU 2014-09”). This ASU, as amended, superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. To date, the Company has identified the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Based on the evaluation performed to date, we have identified similar performance obligations as compared with deliverables and separate units of account previously identified, and we do not expect any change related to the allocation of the transaction price and the timing of our revenue to have a material impact on our consolidated financial statements or results of operations.  The Company implemented ASU 2014-09 as of January 1, 2018 using the modified retrospective approach with 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 toincrease 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.  To date, the Company has identified each of its leases and is in the process of determining the impact of this new guidance on each of the identified leases.  The Company does not expect this to impact its operating results or cash flows, however, the Company does expect to carry a portion of future lease costs as an asset and a liability on its balance sheet.

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 implemented this in 2018 with no impact on the Company’s 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 during 2018 was 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 the sale of the Methane Project and other related assets in 2018.  The Company sold all of the Methane Project and all its other methane facility assets, except the applicable U.S. patent, on January 26, 2018.

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.

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, 2018 and December 31, 2017 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of March 31, 2018 and December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at March 31, 2018 and December 31, 2017.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at March 31, 2018 and December 31, 2017.

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, 2018			December 31, 2017
Oil and gas properties	$	5,733		$	5,704
Unevaluated properties		—			—
Accumulated depreciation, depletion, and amortization		(1,163	)		(984	)
Oil and gas properties	$	4,570		$	4,720

The Company recorded depletion expense of $172,000 and $204,000 for the three months ended March 31, 2018 and 2017, respectively.  During the three months ended March 31, 2018 and 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $7,000 gain on asset retirement obligations and a $1,000 gain on asset retirement obligations, respectively.

(9) Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the three months ended March 31, 2018 (in thousands):

Balance December 31, 2017	$	2,270
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(14	)
Balance March 31, 2018	$	2,292

(10) Long-Term Debt

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

	March 31, 2018			December 31, 2017
Note payable to a financial institution, with interest only payment until maturity	$	—		$	—
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		159			90
Total debt		159			90
Less current maturities		(56	)		(41	)
Long-term debt, less current maturities	$	103		$	49

At March 31, 2018, the Company had a revolving credit facility with Prosperity Bank.  This has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of March 31, 2018, the Company’s borrowing base was $2 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2018, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At March 31, 2018, the interest rate on this credit facility was 5.25%.  The Company was in compliance with all covenants during the quarter ended March 31, 2018.

13

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

(11) Discontinued Operations

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

	March 31, 2018		December 31, 2017
Accounts receivable	$	—	$	91
Other current assets		—		30
Discontinued operations included in current assets	$	—	$	121
Property, plant, and equipment	$	—	$	1,681
Accumulated depreciation, depletion, and amortization		—		(184	)
Discontinued operations included in non-current assets	$	—	$	1,497
Accounts payable - trade	$	32	$	27
Accrued and other current liabilities		—		16
Discontinued operations included in current liabilities	$	32	$	43

	For the Three Months Ended March 31,
	2018			2017
Revenues	$	6		$	135
Production costs and taxes		(50	)		(163	)
Depreciation, depletion, and amortization		(4	)		(15	)
Interest income		1			—
Gain on sale of assets		1,157			—
Deferred income tax benefit		—			—
Net income (loss) from discontinued operations	$	1,110		$	(43	)

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

(12) Fair Value Measurements

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

14

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

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

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

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of March 31, 2018 and December 31, 2017.

(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.

In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties.  Since March 31, 2018, the Company has entered into a drilling commitment in the amount of approximately $45,000.  The work associated with this commitment was completed in April 2018.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions 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, 2018, the reductions were approximately $421,000.  The Company has not accrued any liabilities associated with these compensation reductions.

15

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Legal Proceedings

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

16

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 2018, 30.6 MBbl gross of oil were sold from the Company’s properties.  Of the 30.6 MBbl sold, 23.7 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 2018 of 23.7 MBbl of oil compares to net sales of 26.0 MBbl of oil during the first three months of 2017.  The Company’s net revenue from its oil and gas properties was $1.4 million during the first three months of 2018 compared to $1.2 million during the first three months of 2017.  This increase in net revenue was primarily due to a $261,000 increase related to an $11.04 per barrel increase in the average oil price from $46.32 per barrel during the first three months of 2017 to $57.36 per barrel during the first three months of 2018, partially offset by a $107,000 decrease related to the 2.3 MBbl decrease in sales volumes.  The 2.3 MBbl decrease was primarily due to natural declines and timing of crude pickup by the refineries.

Comparison of the Quarters Ended March 31, 2018 and 2017

The Company reported a net income from continuing operations of $133,000 or $0.01 per share of common stock during the first quarter of 2018 compared to a net loss from continuing operations of $170,000 or $0.02 per share of common stock during the first quarter of 2017.  The $303,000 increase in net income was primarily due to a $158,000 increase in revenues, a $78,000 decrease in production cost and taxes, a $38,000 decrease in DD&A, a $16,000 increase in gain on asset sales, and a $15,000 decrease in net interest expense.

The Company recognized $1.4 million in revenues during the first quarter of 2018 compared to $1.2 million during the first quarter of 2017. The $158,000 increase in net revenue was primarily due to a $261,000 increase related to an $11.04 per barrel increase in the average oil price from $46.32 per barrel during the first three months of 2017 to $57.36 per barrel during the first three months of 2018, partially offset by a $107,000 decrease related to the 2.3 MBbl decrease in sales volumes.  The 2.3 MBbl decrease was primarily due to natural declines and timing of crude pickup by the refineries

Production cost and taxes decreased $78,000 from $808,000 during the first quarter of 2017 to $730,000 during the first quarter of 2018.  This decrease was primarily due to a $146,000 change in the oil inventory quarterly adjustment, and a $14,000 decrease in Kansas property taxes, partially offset by a $34,000 increase in well and facility repair costs, a $15,000 increase in chemical costs, and an $11,000 increase in franchise tax costs.

DD&A decreased $38,000 from $221,000 during the first quarter of 2017 to $183,000 during the first quarter of 2018.  This decrease was primarily due to a $18,000 decrease related to a 2.3 MBbl decrease in oil sales volumes, and a $14,000 decrease related to a lower oil depletion rate.

The $16,000 increase in gain on asset sales was related to disposal of certain field vehicle in 2018.  The $15,000 decrease in net interest expense was primarily due to borrowings on the credit facility during the first quarter of 2017.

Liquidity and Capital Resources

At March 31, 2018, the Company had a revolving credit facility with Prosperity Bank.  This has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of March 31, 2018, the Company’s borrowing base was $2 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2018, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At March 31, 2018, the interest rate on this credit facility was 5.25%.  The Company was in compliance with all covenants during the quarter ended March 31, 2018.

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

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $2.0 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.

17

Net cash provided by operating activities from continuing operations was $71,000 during the first three months of 2018 compared to $72,000 provided by operating activities from continuing operations during the first three months of 2017.  Cash flow used in working capital was $270,000 during the first three months of 2018 compared to $23,000 used in working capital during the first three months of 2017. The $247,000 increase in cash flow used in working capital was primarily due to changes in inventory.  Net cash used in investing activities from continuing operations was $41,000 during the first three months of 2018 compared to $7,000 used in investing activities from continuing operations during the first three months of 2017.  The $34,000 increase in net cash used in investing activities from continuing operations was primarily a result of a $25,000 increase in drilling cost incurred during first three months of 2018 compared to the first three months of 2017, and $19,000 related to acquisition of new field vehicles compared to the first three months of 2016.  Cash flow used in financing activities from during the first three months of 2018 was $16,000 compared to $247,000 provided by financing activities during the first three months of 2017.  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

Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers.

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.

In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties.  Since March 31, 2018, the Company has entered into a drilling commitment in the amount of approximately $45,000.  The work associated with this commitment was completed in April 2018.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions 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, 2018, the reductions were approximately $421,000.  The Company has not accrued any liabilities associated with these compensation reductions.

Legal Proceedings

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

18

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, 2018, the Company’s borrowing base was approximately $2 million of which zero had been drawn down by the Company.  The Company’s next periodic borrowing base review will take place in July 2018.

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 2018 ranged from a low of $56.66 per barrel to a high of $58.02 per barrel.

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

Interest Rate Risk

At March 31, 2018, the Company had debt outstanding of approximately $159,000, none of which was owed on its credit facility with Prosperity Bank.  As of March 31, 2018, 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, 2018 was 5.25%.  The Company’s remaining debt of $159,000 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, 2018.  The Company did not have any open derivative contracts relating to interest rates at March 31, 2018 or December 31, 2017.

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

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

Refer to Item 1A Risk Factors in the Company’s Report on Form 10-K for the year ended December 31, 2017 filed on March 28, 2018 which is incorporated by this reference.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5. OTHER INFORMATION

None.

20

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 15, 2018
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, 2018.

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 15, 2018
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, 2018.

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 15, 2018
	By:	/s/ Michael J. Rugen
		Michael J. Rugen
		Chief Executive Officer and Chief Financial Officer

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Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 07, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Entity Registrant Name	TENGASCO INC
Entity Central Index Key	0001001614
Entity Filer Category	Smaller Reporting Company
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		10,624,493

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current
Cash and cash equivalents	$ 2,916	$ 185
Accounts receivable, less allowance for doubtful accounts of $14	550	517
Accounts receivable - related party, less allowance for doubtful accounts of $159
Inventory	656	541
Other current assets	219	134
Discontinued operations included in current assets		121
Total current assets	4,341	1,498
Loan fees, net	12	13
Oil and gas properties, net (full cost accounting method)	4,570	4,720
Other property and equipment, net	243	135
Deferred tax asset	242	242
Discontinued operations included in non-current assets		1,497
Total assets	9,408	8,105
Current liabilities
Accounts payable - trade	133	181
Accounts payable - other	159	159
Accrued and other current liabilities	211	187
Current maturities of long-term debt	56	41
Discontinued operations included in current liabilities	32	43
Total current liabilities	591	611
Asset retirement obligation	2,292	2,270
Long term debt, less current maturities	103	49
Total liabilities	2,986	2,930
Commitments and contingencies (Note 13)
Stockholders' equity
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding
Common stock, $.001 par value, authorized 100,000,000 shares, 10,624,493 and 10,619,924 shares issued and outstanding	11	11
Additional paid-in capital	58,257	58,253
Accumulated deficit	(51,846)	(53,089)
Total stockholders' equity	6,422	5,175
Total liabilities and stockholders' equity	$ 9,408	$ 8,105

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
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	10,624,493	10,619,924
Common stock, shares outstanding	10,624,493	10,619,924
Related Party [Member]
Allowance for doubtful accounts	$ 159	$ 159
Series A Preferred Stock [Member]
Preferred stock, par value	$ 0.0001	$ 0.0001
Preferred stock, shares authorized	10,000	10,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0

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Condensed Consolidated Statements Of Operations - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
Revenue	$ 1,367,000	$ 1,209,000
Cost and expenses
Production costs and taxes	730,000	808,000
Depreciation, depletion, and amortization	183,000	221,000
General and administrative	336,000	334,000
Impairment
Total cost and expenses	1,249,000	1,363,000
Net income (loss) from operations	118,000	(154,000)
Other expense
Net interest expense	(1,000)	(16,000)
Gain on sale of assets	16,000
Total other expenses	15,000	(16,000)
Income (loss) from continuing operations before income tax	133,000	(170,000)
Deferred income tax benefit
Net income (loss) from continuing operations	133,000	(170,000)
Net income (loss) from discontinued operations	1,110,000	(43,000)
Net income (loss)	$ 1,243,000	$ (213,000)
Net income (loss) per share - Basic and Fully Diluted
Continuing operations	$ 0.01	$ (0.02)
Discontinued operations	$ 0.10	$ (0.01)
Shares used in computing earnings per share
Basic and fully diluted	10,624,442	8,452,132
Oil And Gas Proeprties Revenue [Member]
Revenues
Revenue	$ 1,367,000	$ 1,209,000

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Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities
Net income (loss) from continuing operations	$ 133	$ (170)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	183	221
Amortization of loan fees-interest expense	1	4
Accretion on asset retirement obligation	36	36
(Gain) loss on assets sales	(16)
Stock based compensation	4	4
Changes in assets and liabilities:
Accounts receivable	(33)	44
Inventory and other assets	(200)	56
Accounts payable	(48)	(63)
Accrued and other current liabilities	18	(50)
Settlement on asset retirement obligation	(7)	(10)
Net cash provided by operating activities - continuing operations	71	72
Net cash provided by (used in) operating activities - discontinued operations	67	(160)
Net cash provided by (used in) operating activities	138	(88)
Investing activities
Additions to oil and gas properties	(32)	(7)
Prooceeds from sale of oil and gas properties	3
Additions to other property & equipment	(19)
Proceeds from sale of other property and equipment	7
Net cash used in investing activities - continuing operations	(41)	(7)
Net cash provided by investing activities - discontinued operations	2,650
Net cash provided by (used in) investing activities	2,609	(7)
Financing activities
Repayments of borrowings	(116)	(2,815)
Proceeds from borrowings	100	400
Proceeds from stock issuance in rights offering		2,699
Costs of stock issuance in rights offering		(37)
Net cash provided by (used in) financing activities - continuing operations	(16)	247
Net cash provided by financing activities	(16)	247
Net change in cash and cash equivalents	2,731	152
Net change in cash and cash equivalents	2,731	152
Cash and cash equivalents, beginning of period	185	76
Cash and cash equivalents, end of period	2,916	228
Supplemental cash flow information:
Cash interest payments		12
Supplemental non-cash investing and financing activities:
Financed company vehicles	109
Costs of stock issuance in rights offering		$ (140)
Capital expenditures included in accounts payable and accrued liabilities	$ 6

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Description Of Business And Significant Accounting Policies

3 Months Ended

Mar. 31, 2018

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”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018 for $2.65 million. (See Note 11. Discontinued Operations)

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of March 31, 2018 and March 31, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2017 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, 2018 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Principles of Consolidation

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

Use of Estimates

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

Revenue Recognition

Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers.  The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

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

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

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

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

	Three Months Ended
	March 31, 2018	March 31, 2017
Revenues (in thousands):
Crude oil	$1,357	$1,203
Salt water disposal fees	10	6
Total	$1,367	$1,209

There were no natural gas imbalances at March 31, 2018 or December 31, 2017. 

Cash and Cash Equivalents

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

Inventory

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

	March 31,		December 31,
	2018		2017
Oil – carried at cost	$	551	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	656	$	541

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities.  Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized.  Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had $0 in unevaluated properties as of March 31, 2018 and December 31, 2017.  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 may not be reversed in a later period.

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, 2018 and December 31, 2017.

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

	March 31,		December 31,
	2018		2017
Revenue	$	519	$	479
Joint interest		23		23
Other		22		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	550	$	517

Reclassifications

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

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Liquidity

3 Months Ended

Mar. 31, 2018

Liquidity [Abstract]

Liquidity

(2) Liquidity

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $2.0 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.

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Income Taxes

3 Months Ended

Mar. 31, 2018

Income Taxes [Abstract]

Income Taxes

(3)  Income Taxes

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

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

At December 31, 2017, federal net operating loss carryforwards amounted to approximately $30.2 million which expire between 2019 and 2036. The net total deferred tax asset was $242,000 at March 31, 2018 and December 31, 2017.  In 2017, The Company released a portion of the allowance related to the Company’s Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act.  The Company recorded an allowance on the remaining deferred tax asset at March 31, 2018 and December 31, 2017 primarily due to cumulative losses incurred during the 3 years ended December 31, 2017.  The Company expects to utilize its net operating losses and reduce its valuation allowance to offset taxable income resulting from the sale of the methane facility assets.There were no recorded unrecognized tax benefits at March 31, 2018. 

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Capital Stock

3 Months Ended

Mar. 31, 2018

Capital Stock [Abstract]

Capital Stock

(4) Capital Stock

Common Stock

On January 2, 2018, 4,569 common shares were issued in the aggregate to the Company’s four directors and CFO and interim CEO.

Rights Agreement

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

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

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

The Rights will expire prior to the earlier of March 16, 2020; or a date the Board of Directors determines by resolution in its business judgment that the Agreement is no longer necessary or appropriate; or in certain other specified circumstances.

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

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

Preferred Stock

Series A Preferred Stock has a par value of $0.0001 and 10,000 shares have been designated.  No shares of Series A Preferred Stock have been issued by the Company pursuant to the Rights Agreement described above or otherwise.

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Earnings Per Common Share

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	133	$	(170)
Net income (loss) from discontinued operations	$	1,110	$	(43)
Weighted average shares (denominator):
Weighted average shares – basic		10,624,442		8,452,132
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares – dilutive		10,624,442		8,452,132
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.01	$	(0.02)
Discontinued operations	$	0.10	$	(0.01)

Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter were excluded from diluted shares.

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Recent Accounting Pronouncements

3 Months Ended

Mar. 31, 2018

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

(6)  Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09 Revenue from Contracts with Customers (“ASU 2014-09”). This ASU, as amended, superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. To date, the Company has identified the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Based on the evaluation performed to date, we have identified similar performance obligations as compared with deliverables and separate units of account previously identified, and we do not expect any change related to the allocation of the transaction price and the timing of our revenue to have a material impact on our consolidated financial statements or results of operations.  The Company implemented ASU 2014-09 as of January 1, 2018 using the modified retrospective approach with 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 toincrease 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.  To date, the Company has identified each of its leases and is in the process of determining the impact of this new guidance on each of the identified leases.  The Company does not expect this to impact its operating results or cash flows, however, the Company does expect to carry a portion of future lease costs as an asset and a liability on its balance sheet.

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 implemented this in 2018 with no impact on the Company’s operating results or cash flows.

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Related Party Transactions

3 Months Ended

Mar. 31, 2018

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 during 2018 was 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 the sale of the Methane Project and other related assets in 2018.  The Company sold all of the Methane Project and all its other methane facility assets, except the applicable U.S. patent, on January 26, 2018. 

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. 

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, 2018 and December 31, 2017 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of March 31, 2018 and December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at March 31, 2018 and December 31, 2017.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at March 31, 2018 and December 31, 2017.

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Oil And Gas Properties

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
Oil and gas properties	$	5,733	$	5,704
Unevaluated properties		—		—
Accumulated depreciation, depletion, and amortization		(1,163)		(984)
Oil and gas properties	$	4,570	$	4,720

The Company recorded depletion expense of $172,000 and $204,000 for the three months ended March 31, 2018 and 2017, respectively.  During the three months ended March 31, 2018 and 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $7,000 gain on asset retirement obligations and a $1,000 gain on asset retirement obligations, respectively.

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Asset Retirement Obligation

3 Months Ended

Mar. 31, 2018

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, 2018(in thousands):

Balance December 31, 2017	$	2,270
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(14)
Balance March 31, 2018	$	2,292

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Long-Term Debt

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
Note payable to a financial institution, with interest only payment until maturity	$	—	$	—
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		159		90
Total debt		159		90
Less current maturities		(56)		(41)
Long-term debt, less current maturities	$	103	$	49

At March 31, 2018, the Company had a revolving credit facility with Prosperity Bank.  This has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of March 31, 2018, the Company’s borrowing base was $2 million.  The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility includes certain covenants with which the Company is required to comply.  At March 31, 2018, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At March 31, 2018, the interest rate on this credit facility was 5.25%.  The Company was in compliance with all covenants during the quarter ended March 31, 2018.

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

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Discontinued Operations

3 Months Ended

Mar. 31, 2018

Discontinued Operations [Abstract]

Discontinued Operations

(11)  Discontinued Operations

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

	March 31,		December 31,
	2018		2017
Accounts receivable	$	—	$	91
Other current assets		—		30
Discontinued operations included in current assets	$	—	$	121
Property, plant, and equipment	$	—	$	1,681
Accumulated depreciation, depletion, and amortization		—		(184)
Discontinued operations included in non-current assets	$	—	$	1,497
Accounts payable - trade	$	32	$	27
Accrued and other current liabilities		—		16
Discontinued operations included in current liabilities	$	32	$	43
	For the Three Months Ended
	March 31,
	2018		2017
Revenues	$	6	$	135
Production costs and taxes		(50)		(163)
Depreciation, depletion, and amortization		(4)		(15)
Interest income		1		—
Gain on sale of assets		1,157		—
Deferred income tax benefit		—		—
Net income (loss) from discontinued operations	$	1,110	$	(43)

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

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Fair Value Measurements

3 Months Ended

Mar. 31, 2018

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, 2018 and December 31, 2017.

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Commitments And Contingencies

3 Months Ended

Mar. 31, 2018

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.

In the normal course of business, the Company enters into commitments to spend capital on oil and gas properties.  Since March 31, 2018, the Company has entered into a drilling commitment in the amount of approximately $45,000.  The work associated with this commitment was completed in April 2018.

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended March 31, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions 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, 2018, the reductions were approximately $421,000.  The Company has not accrued any liabilities associated with these compensation reductions.

Legal Proceedings

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

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Description Of Business And Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2018

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, 2018 and March 31, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 2017 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, 2018 are not necessarily indicative of the results that may be expected for the year ended December 31, 2018. It is suggested that these condensed consolidated financial statements be read in conjunction with the Company’s consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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

Effective January 1, 2018, the Company adopted ASU 2014-09 Revenue from Contracts with Customers.  The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

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

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

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

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

	Three Months Ended
	March 31, 2018	March 31, 2017
Revenues (in thousands):
Crude oil	$1,357	$1,203
Salt water disposal fees	10	6
Total	$1,367	$1,209

There were no natural gas imbalances at March 31, 2018 or December 31, 2017. 

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 market value.  The cost component of the oil inventory is calculated using the average cost per barrel for the three months ended March 31, 2018 and December 31, 2017.  These costs includes production costs and taxes, allocated general and administrative costs, depletion, and allocated interest cost.  The market value component is calculated using the average March 2018 and December 2017 oil sales prices received from the Company’s Kansas properties.  In addition, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value.  The cost component of the equipment and materials inventory represents the original cost paid for the equipment and materials.  The market component is based on estimated sales value for similar equipment and materials at the end of each period.  At March 31, 2018 and December 31, 2017, inventory consisted of the following (in thousands):

	March 31,		December 31,
	2018		2017
Oil – carried at cost	$	551	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	656	$	541

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 acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.  The Company had $0 in unevaluated properties as of March 31, 2018 and December 31, 2017.  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 may not be reversed in a later period.

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, 2018 and December 31, 2017.

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

	March 31,		December 31,
	2018		2017
Revenue	$	519	$	479
Joint interest		23		23
Other		22		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	550	$	517

Reclassifications

Reclassifications

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

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Description Of Business And Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2018

Description Of Business And Significant Accounting Policies [Abstract]

Disaggregation Of Revenue

	Three Months Ended
	March 31, 2018	March 31, 2017
Revenues (in thousands):
Crude oil	$1,357	$1,203
Salt water disposal fees	10	6
Total	$1,367	$1,209

Inventory

	March 31,		December 31,
	2018		2017
Oil – carried at cost	$	551	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	656	$	541

Accounts Receivable

	March 31,		December 31,
	2018		2017
Revenue	$	519	$	479
Joint interest		23		23
Other		22		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	550	$	517

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Earnings Per Common Share (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Common Share [Abstract]

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

	For the Three Months Ended
	March 31,
	2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	133	$	(170)
Net income (loss) from discontinued operations	$	1,110	$	(43)
Weighted average shares (denominator):
Weighted average shares – basic		10,624,442		8,452,132
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares – dilutive		10,624,442		8,452,132
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.01	$	(0.02)
Discontinued operations	$	0.10	$	(0.01)

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Oil And Gas Properties (Tables)

3 Months Ended

Mar. 31, 2018

Oil And Gas Properties [Abstract]

Schedule Of Oil And Gas Properties

	March 31,		December 31,
	2018		2017
Oil and gas properties	$	5,733	$	5,704
Unevaluated properties		—		—
Accumulated depreciation, depletion, and amortization		(1,163)		(984)
Oil and gas properties	$	4,570	$	4,720

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Asset Retirement Obligation (Tables)

3 Months Ended

Mar. 31, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Transactions

Balance December 31, 2017	$	2,270
Accretion expense		36
Liabilities incurred		—
Liabilities settled		(14)
Balance March 31, 2018	$	2,292

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2018

Long-Term Debt [Abstract]

Schedule Of Long-term Debt To Unrelated Entites

	March 31,		December 31,
	2018		2017
Note payable to a financial institution, with interest only payment until maturity	$	—	$	—
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10		159		90
Total debt		159		90
Less current maturities		(56)		(41)
Long-term debt, less current maturities	$	103	$	49

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2018

Discontinued Operations [Abstract]

Schedule Of The Amounts In Net Loss From Discontinued Operations

	March 31,		December 31,
	2018		2017
Accounts receivable	$	—	$	91
Other current assets		—		30
Discontinued operations included in current assets	$	—	$	121
Property, plant, and equipment	$	—	$	1,681
Accumulated depreciation, depletion, and amortization		—		(184)
Discontinued operations included in non-current assets	$	—	$	1,497
Accounts payable - trade	$	32	$	27
Accrued and other current liabilities		—		16
Discontinued operations included in current liabilities	$	32	$	43
	For the Three Months Ended
	March 31,
	2018		2017
Revenues	$	6	$	135
Production costs and taxes		(50)		(163)
Depreciation, depletion, and amortization		(4)		(15)
Interest income		1		—
Gain on sale of assets		1,157		—
Deferred income tax benefit		—		—
Net income (loss) from discontinued operations	$	1,110	$	(43)

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Description Of Business And Significant Accounting Policies (Narrative) (Details) - USD ($)		1 Months Ended	3 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]
Material natural gas imbalances			$ 0		$ 0
Unevaluated properties			0		$ 0
Impairment
Sale of methane facility assets	$ 2,650,000	$ 2,650,000

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Description Of Business And Significant Accounting Policies (Disaggregation Of Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 1,367	$ 1,209
Crude Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,357	1,203
Salt Water Disposal Fees [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 10	$ 6

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Description Of Business And Significant Accounting Policies (Inventory) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]
Oil - carried at cost	$ 551	$ 436
Equipment and materials - carried at market	105	105
Total inventory	$ 656	$ 541

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Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (14)	$ (14)
Total accounts receivable	550	517
Revenue [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	519	479
Joint Interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	23	23
Other [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 22	$ 29

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Liquidity (Narrative) (Details) - USD ($)		1 Months Ended	3 Months Ended		12 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Liquidity [Line Items]
Net loss from operations			$ 1,243,000	$ (213,000)	$ (574,000)
Sale of methane facility assets	$ 2,650,000	$ 2,650,000
Prosperity Bank [Member]
Liquidity [Line Items]
Credit facility current borrowing capacity			2,000,000
Current funds drawn			$ 0

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Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Taxes [Line Items]
Provision or benefit for income taxes
Unrecognized tax benefits	0
Federal net operating loss carryforwards			$ 30,200,000
Deferred tax asset	$ 242,000		$ 242,000
Minimum [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards expiration between, years	Dec. 31, 2019
Maximum [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards expiration between, years	Dec. 31, 2036

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Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Net deferred tax asset	$ 242,000	$ 242,000

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Capital Stock (Narrative) (Details)			3 Months Ended
	Jan. 02, 2018 item shares	Mar. 17, 2017 $ / shares	Mar. 31, 2018 $ / shares shares	Dec. 31, 2017 $ / shares shares	Mar. 16, 2017 $ / shares
Capital Stock [Line Items]
Common stock, par value | $ / shares			$ 0.001	$ 0.001
Preferred stock, shares authorized			25,000,000	25,000,000
Dividends conversion ratio			0.001
Exercise price | $ / shares					$ 1.10
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]
Date declared			Mar. 17, 2017
Date to be paid			Mar. 27, 2017
Date of record			Mar. 16, 2017
Directors, CFO And Interim CEO [Member]
Capital Stock [Line Items]
Common stock, New shares issued	4,569
Number of directors | item	4
Series A Preferred Stock [Member]
Capital Stock [Line Items]
Preferred stock, shares authorized			10,000	10,000
Preferred stock, shares issued			0	0
Series A Preferred Stock [Member] | Rights Plan [Member]
Capital Stock [Line Items]
Preferred stock, shares issued			0

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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, 2018	Mar. 31, 2017
Earnings Per Common Share [Abstract]
Net income (loss) from continuing operations	$ 133	$ (170)
Net income (loss) from discontinued operations	$ 1,110	$ (43)
Weighted average shares - basic	10,624,442	8,452,132
Dilution effect of share-based compensation, treasury method
Weighted average shares - dilutive	10,624,442	8,452,132
Continuing operations	$ 0.01	$ (0.02)
Discontinued operations	$ 0.10	$ (0.01)

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Related Party Transactions (Narrative) (Details) - USD ($)		3 Months Ended	108 Months Ended
	Dec. 18, 2007	Mar. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Working interest percent	15.00%
Related party allowance for doubtful accounts receivable		$ 14,000	$ 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	159,000
Past due related parties accounts payable		159,000	159,000
Hoactzin Partners, L.P. [Member] | Methane Project [Member]
Related Party Transaction [Line Items]
Net profits			0
Related Party [Member]
Related Party Transaction [Line Items]
Related party allowance for doubtful accounts receivable		159,000	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	159,000	159,000
Accounts receivable - related parties balance		$ 159,000	$ 159,000	$ 0

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Oil And Gas Properties (Narrative) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Oil And Gas Properties [Abstract]
Depletion expense	$ 172,000	$ 204,000
Impairment
Gain on asset retirement obligations	$ 7,000	$ 1,000

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Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Oil And Gas Properties [Abstract]
Oil and gas properties	$ 5,733	$ 5,704
Accumulated depreciation, depletion, and amortization	(1,163)	(984)
Oil and gas properties	$ 4,570	$ 4,720

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Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Asset Retirement Obligation [Abstract]
Balance	$ 2,270
Accretion expense	36	$ 36
Liabilities incurred
Liabilities settled	(14)
Balance	$ 2,292

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Long-Term Debt (Narrative) (Details) - Prosperity Bank [Member]		3 Months Ended
	Mar. 21, 2018 USD ($)	Mar. 31, 2018 USD ($)
Debt Instrument [Line Items]
Credit facility maturity date		Jul. 31, 2020
Rate above prime	0.50%
Interest rate	5.00%	5.25%
Credit facility maximum borrowing capacity	$ 2,000,000	$ 50,000,000
Credit facility current borrowing capacity		2,000,000
Credit facility amount outstanding		0
Loans And Letters Of Credit [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		$ 50,000,000
Maximum [Member]
Debt Instrument [Line Items]
Funded debt to EBITDA		3.5
Minimum [Member]
Debt Instrument [Line Items]
Current ratio		1
Interest coverage		3.0

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Long-Term Debt (Schedule Of Long-Term Debt To Unrelated Entities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
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	$ 159	$ 90
Total long-term debt	159	90
Less current maturities	(56)	(41)
Long-term debt, less current maturities	103	$ 49
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%

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Long-Term Debt (Schedule Of Future Debt Payments) (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Long-Term Debt [Abstract]
Total long-term debt	$ 159	$ 90

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Discontinued Operations (Schedule Of The Amounts In Net Loss From Discontinued Operations) (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued operations included in current assets					$ 121
Discontinued operations included in non-current assets					1,497
Discontinued operations included in current liabilities			$ 32		43
Net income (loss) from discontinued operations			1,110	$ (43)
Sale of methane facility assets	$ 2,650	$ 2,650
Disposal Group, Not Discontinued Operations [Member] | Methane Facilities [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable					91
Other current assets					30
Discontinued operations included in current assets					121
Property, plant, and equipment					1,681
Accumulated depreciation, depletion, and amortization					(184)
Discontinued operations included in non-current assets					1,497
Accounts payable - trade			32		27
Accrued and other current liabilities					16
Discontinued operations included in current liabilities			32		$ 43
Revenues			6	135
Production costs and taxes			(50)	(163)
Depreciation, depletion, and amortization			(4)	(15)
Interest income			1
Gain on sale of assets			1,157
Net income (loss) from discontinued operations			$ 1,110	$ (43)

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Commitments And Contingencies (Narrative) (Details)	3 Months Ended	39 Months Ended
	Mar. 31, 2018 USD ($) $ / bbl	Mar. 31, 2018 USD ($)	Sep. 30, 2012 USD ($)
Loss Contingencies [Line Items]
Decrease in compensation		$ 421,000
Period of trailing average of WTI	30 days
Drilling commitment	$ 45,000	$ 45,000
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 | $ / bbl	70
Compensation reimbursement at WTI posting | $ / bbl	85