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 September 30, 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   ☒ Yes    ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ☐	Accelerated filer  ☐
Non-accelerated filer  ☐	Smaller reporting company  ☒
	Emerging growth company  ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes ☐   No ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,639,290 common shares at November 5, 2018.

TABLE OF CONTENTS

		PAGE
PART I.	FINANCIAL INFORMATION
	ITEM 1. FINANCIAL STATEMENTS
	*    Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	3
	*    Unaudited Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2018 and 2017	5
	*    Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 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	20
	ITEM 4. CONTROLS AND PROCEDURES	21
PART II.	OTHER INFORMATION	21
	ITEM 1. LEGAL PROCEEDINGS	21
	ITEM 1A. RISK FACTORS	21
	ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	21
	ITEM 3. DEFAULTS UPON SENIOR SECURITIES	21
	ITEM 4. MINE SAFTY DISCLOSURES	21
	ITEM 5. OTHER INFORMATION	21
	ITEM 6. EXHIBITS	22
	*    SIGNATURES	23
	*    CERTIFICATIONS

Tengasco, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

(in thousands, except share data)

	September 30, 2018		December 31, 2017
Assets
Current
Cash and cash equivalents	$	3,402	$	185
Accounts receivable, less allowance for doubtful accounts of $14		695		517
Accounts receivable – related party, less allowance for doubtful accounts of $159		—		—
Inventory		646		541
Other current assets		173		134
Discontinued operations included in current assets		—		121
Total current assets		4,916		1,498
Loan fees, net		10		13
Oil and gas properties, net (full cost accounting method)		4,839		4,720
Other property and equipment, net		212		135
Accounts receivable - noncurrent		121		242
Discontinued operations included in non-current assets		—		1,497
Total assets	$	10,098	$	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)

	September 30, 2018			December 31, 2017
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable – trade	$	361		$	181
Accounts payable – other		159			159
Accrued and other current liabilities		250			187
Current maturities of long-term debt		60			41
Discontinued operations included in current liabilities		—			43
Total current liabilities		830			611
Asset retirement obligation		2,363			2,270
Long term debt, less current maturities		76			49
Total liabilities		3,269			2,930
Commitments and contingencies (Note 13)
Stockholders’ equity
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding		—			—
Common stock, $.001 par value, authorized 100,000,000 shares, 10,624,493 and 10,619,924 shares issued and outstanding		11			11
Additional paid–in capital		58,257			58,253
Accumulated deficit		(51,439	)		(53,089	)
Total stockholders’ equity		6,829			5,175
Total liabilities and stockholders’ equity	$	10,098		$	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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues
Oil and gas properties	$	1,654		$	1,035		$	4,497		$	3,383
Total revenues		1,654			1,035			4,497			3,383
Cost and expenses
Production costs and taxes		862			907			2,502			2,595
Depreciation, depletion, and amortization		219			210			599			658
General and administrative		288			268			896			860
Total cost and expenses		1,369			1,385			3,997			4,113
Net income (loss) from operations		285			(350	)		500			(730	)
Other income (expense)
Interest expense		(1	)		(16	)		(4	)		(36	)
Gain on sale of assets		14			5			34			5
Total other income (expense)		13			(11	)		30			(31	)
Net income (loss) from operations before income tax		298			(361	)		530			(761	)
Deferred income tax benefit		—			—			—			—
Net income (loss) from continuing operations		298			(361	)		530			(761	)
Net income from discontinued operations		—			46			1,120			55
Net income (loss)	$	298		$	(315	)	$	1,650		$	(706	)
Net income (loss) per share - basic and fully diluted
Continuing operations	$	0.03		$	(0.03	)	$	0.05		$	(0.08	)
Discontinued operations	$	0.00		$	0.00		$	0.11		$	0.01
Shares used in computing earnings per share
Basic and fully diluted		10,624,493			10,614,402			10,624,476			9,899,696

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

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 September 30, 2018 and September 30, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 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 nine months ended September 30, 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 and request them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.  When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis.  Fees and other deductions incurred prior to transfer of control are recorded as production costs.  Revenues are reported net of fees and other deductions incurred after transfer of control.

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 and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations.  (See Note 11. Discontinued Operations)

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 and nine months ended September 30, 2018 and 2017 (in thousands):

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

There were no natural gas imbalances at September 30, 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 September 30, 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 September 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 September 30, 2018 and December 31, 2017, inventory consisted of the following (in thousands):

	September 30, 2018		December 31, 2017
Oil – carried at cost	$	541	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	646	$	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 September 30, 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.  The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2018 and 2017.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at September 30, 2018 and December 31, 2017.

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

	September 30, 2018		December 31, 2017
Revenue	$	510	$	479
Tax		121		—
Joint interest		54		23
Other		24		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	695	$	517

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

Reclassifications

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

(2) 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 borrowing base of $3 million, subject to a credit limit based on current covenants of approximately $2.74 million, with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

9

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(3) Income Taxes

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

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

The Company has computed an estimated annual effective tax rate for the current reporting year of 0% based upon the year-to-date and forecasted book income and cumulative loss position for the three year period ended December 31, 2018.  Accordingly, the Company has recorded no provision or benefit for income taxes for the current reporting period.

At December 31, 2017, federal net operating loss carryforwards amounted to approximately $34.8 million which expire between 2019 and 2036. In 2017, the Company released a portion of the valuation allowance related to the Company’s Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act.  The net total deferred tax asset of $242,000 was recorded as a non-current receivable at December 31, 2017.  At September 30, 2018, based upon its expected recovery, the Company reclassified $121,000 of this tax related non-current receivable as a current receivable.  The Company recorded a valuation allowance on the remaining deferred tax assets at September 30, 2018 and December 31, 2017 as such amounts were not considered to be more-likely-than-not realizable due to cumulative losses incurred during the preceding 3 year period.  There were no recorded unrecognized tax benefits at September 30, 2018.

(4) Capital Stock

Common Stock

There were no common shares issued during the three months ended September 30, 2018.

On October 1, 2018, 14,797 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 if the Company’s experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock.

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

10

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

Preferred Stock

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

(5) Earnings per Common Share

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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2018		2017			2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	298	$	(361	)	$	530	$	(761	)
Net income from discontinued operations	$	—	$	46		$	1,120	$	55
Weighted average shares (denominator):
Weighted average shares – basic		10,624,493		10,614,402			10,624,476		9,899,696
Dilution effect of share-based compensation, treasury method		—		—			—		—
Weighted average shares – dilutive		10,624,493		10,614,402			10,624,476		9,899,696
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.03	$	(0.03	)	$	0.05	$	(0.08	)
Discontinued operations	$	0.00	$	0.00		$	0.11	$	0.01

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

(6) Recent Accounting Pronouncements

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

(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.

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

As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties.  In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name.  As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet.  Payables related to these past due and ongoing operations remained outstanding at September 30, 2018 and December 31, 2017 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2018 and December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at September 30, 2018 and December 31, 2017.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at September 30, 2018 and December 31, 2017.

(8) Oil and Gas Properties

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

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

The Company recorded depletion expense of $546,000 and $608,000 for the nine months ended September 30, 2018 and 2017, respectively.  During the nine months ended September 30, 2018 and 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” an $8,000 gain on asset retirement obligations and a $2,000 gain on asset retirement obligations, respectively.

12

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(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 nine months ended September 30, 2018 (in thousands):

Balance December 31, 2017	$	2,270
Accretion expense		106
Liabilities incurred		—
Liabilities settled		(13	)
Balance September 30, 2018	$	2,363

(10) Long-Term Debt

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

	September 30, 2018			December 31, 2017
Note payable to a financial institution, with interest only payment until maturity.	$	—		$	—
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $5		136			90
Total  long-term debt		136			90
Less current maturities		(60	)		(41	)
Long-term debt, less current maturities	$	76		$	49

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

On August 24, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30, 2018.  The next borrowing base review will take place in March 2019.

On March 21, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s review of the Company’s owned producing properties was amended to increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020.  The borrowing base remained subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.00% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million.

13

Tengasco, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

(11) Discontinued Operations

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

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

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

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

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

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

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel.  In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  For the period January 1, 2015 through September 30, 2018, the reductions were approximately $445,000.  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.

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

Results of Operations and Financial Condition

During the first nine months of 2018, 94.4 MBbl gross of oil were sold from the Company’s properties.  Of the 94.4 MBbl sold, 73.0 MBbl were net to the Company after required payments to all of the royalty interests and drilling program participants.  The Company’s net sales from its properties during the first nine months of 2018 of 73.0 MBbl of oil compares to net sales of 76.5 MBbl of oil during the first nine months of 2017.  The Company’s net revenue from its oil and gas properties was $4.5 million during the first nine months of 2018 compared to $3.4 million during the first nine months of 2017.  This increase in net revenue was primarily due to a $1.3 million increase related to an $17.35 per barrel increase in the average oil price from $43.92 per barrel during the first nine months of 2017 to $61.27 per barrel during the first nine months of 2018, partially offset by a $154,000 decrease related to the 3.5 MBbl decrease in sales volumes.  The 3.5 MBbl decrease was primarily due to natural declines on the Albers, Albers B, Coddington, Veverka B, and C leases, partially offset by increased production on the Veverka D lease as a result of a polymer performed in the 2^nd quarter 2018, and by increased production on the Nutsch-Buss well as a result of work performed at the end of 2017.

Comparison of the Quarters Ended September 30, 2018 and 2017

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

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

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

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

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

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

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

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

17

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

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

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

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

Gain on sale of assets increased $29,000 from $5,000 during the first nine months of 2017 to $34,000 during the first nine months of 2018.  This increase was primarily related to gains on disposal of field vehicles recorded during 2018.

Liquidity and Capital Resources

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

On August 24, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30, 2018.  The next borrowing base review will take place in March 2019.

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

The Company incurred a net loss of approximately $574,000 in 2017.  In January 2018, the Company sold its methane facility for $2.65 million.  During 2018, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in compliance with its bank covenants.  If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against the credit facility as this facility currently has a $3.0 million borrowing base with no funds currently drawn. This borrowing base in subject to a credit limit of approximately $2.74 million.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

Net cash provided by operating activities from continuing operations was $1.0 million during the first nine months of 2018 compared to $191,000 provided by operating activities from continuing operations during the first nine months of 2017.  Cash flow used in working capital was $190,000 during the first nine months of 2018 compared to $170,000 provided by working capital during the first nine months of 2017. The $360,000 increase in cash flow used in working capital was primarily due to changes in inventory, changes in accrued liabilities, and changes in accounts receivable, partially offset by changes in accounts payable.  The $827,000 increase in cash provided by operating activities was primarily due to a $1.1 million increase in revenues, partially offset by the $360,000 increase in cash flow used in working capital.  Net cash used in investing activities from continuing operations was $466,000 during the first nine months of 2018 compared to $153,000 used in investing activities from continuing operations during the first nine months of 2017.  This increase in cash flow used in investing activities was primarily due to drilling and polymers performed in 2018.  Cash flow used in financing activities from continuing operations during the first nine months of 2018 was $30,000 compared to $153,000 provided by financing activities during the first nine months of 2017.  During the first nine months of 2017, the Company raised approximately $2.7 million in proceeds as a result of a rights offering which closed on February 2, 2017.  The direct costs associated with this rights offering were approximately $242,000, of which $140,000 were incurred during 2016.  The net proceeds from this offering were used primarily to pay off the Company’s credit facility.

18

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

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

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

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel.  In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  For the period January 1, 2015 through September 30, 2018, the reductions were approximately $445,000.  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.

19

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

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

Commodity Risk

The Company's major market risk exposure is in the pricing applicable to its oil production.  Realized pricing is primarily driven by the prevailing worldwide price for crude oil.  Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.  The average monthly Kansas oil prices received during the first nine months of 2018 ranged from a low of $56.66 per barrel to a high of $65.70 per barrel.

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

Interest Rate Risk

At September 30, 2018, the Company had debt outstanding of approximately $136,000, none of which was owed on its credit facility with Prosperity Bank.  As of September 30, 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 September 30, 2018 was 5.75%.  The Company’s remaining debt of $136,000 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 September 30, 2018.  The Company did not have any open derivative contracts relating to interest rates at September 30, 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.

20

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and Chief Financial Officer has concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. The effectiveness of a system of disclosure controls and procedures is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of internal controls, and fraud. Due to such inherent limitations, there can be no assurance that any system of disclosure controls and procedures will be successful in preventing all errors or fraud, or in making all material information known in a timely manner to the appropriate levels of management.

Changes in Internal Controls

During the nine months ended September 30, 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.

21

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

22

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

Dated:  November 14, 2018

TENGASCO, INC.

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

23

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 September 30, 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: November 14, 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 September 30, 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:  November 14, 2018

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

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 05, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
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		10,639,290

XML

Condensed Consolidated Balance Sheets - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Current
Cash and cash equivalents	$ 3,402,000	$ 185,000
Accounts receivable, less allowance for doubtful accounts of $14	695,000	517,000
Accounts receivable - related party, less allowance for doubtful accounts of $159
Inventory	646,000	541,000
Other current assets	173,000	134,000
Discontinued operations included in current assets		121,000
Total current assets	4,916,000	1,498,000
Loan fees, net	10,000	13,000
Oil and gas properties, net (full cost accounting method)	4,839,000	4,720,000
Other property and equipment, net	212,000	135,000
Accounts receivable - noncurrent	121,000	242,000
Discontinued operations included in non-current assets		1,497,000
Total assets	10,098,000	8,105,000
Current liabilities
Accounts payable - trade	361,000	181,000
Accounts payable - other	159,000	159,000
Accrued and other current liabilities	250,000	187,000
Current maturities of long-term debt	60,000	41,000
Discontinued operations included in current liabilities		43,000
Total current liabilities	830,000	611,000
Asset retirement obligation	2,363,000	2,270,000
Long term debt, less current maturities	76,000	49,000
Total liabilities	3,269,000	2,930,000
Commitments and contingencies (Note 13)
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding
Common stock, $.001 par value, authorized 100,000,000 shares, 10,624,493 and 10,619,924 shares issued and outstanding	11,000	11,000
Additional paid-in capital	58,257,000	58,253,000
Accumulated deficit	(51,439,000)	(53,089,000)
Total stockholders' equity	6,829,000	5,175,000
Total liabilities and stockholders' equity	$ 10,098,000	$ 8,105,000

XML

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 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

XML

Condensed Consolidated Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Revenues	$ 1,654,000	$ 1,035,000	$ 4,497,000	$ 3,383,000
Cost and expenses
Production costs and taxes	862,000	907,000	2,502,000	2,595,000
Depreciation, depletion, and amortization	219,000	210,000	599,000	658,000
General and administrative	288,000	268,000	896,000	860,000
Total cost and expenses	1,369,000	1,385,000	3,997,000	4,113,000
Net income (loss) from operations	285,000	(350,000)	500,000	(730,000)
Other income (expense)
Interest expense	(1,000)	(16,000)	(4,000)	(36,000)
Gain on sale of assets	14,000	5,000	34,000	5,000
Total other income (expense)	13,000	(11,000)	30,000	(31,000)
Net income (loss) from operations before income tax	298,000	(361,000)	530,000	(761,000)
Deferred income tax benefit
Net income (loss) from continuing operations	298,000	(361,000)	530,000	(761,000)
Net income from discontinued operations		46,000	1,120,000	55,000
Net income (loss)	$ 298,000	$ (315,000)	$ 1,650,000	$ (706,000)
Net income (loss) per share - basic and fully diluted
Continuing operations	$ 0.03	$ (0.03)	$ 0.05	$ (0.08)
Discontinued operations	$ 0.00	$ 0.00	$ 0.11	$ 0.01
Shares used in computing earnings per share
Basic and fully diluted	10,624,493	10,614,402	10,624,476	9,899,696
Oil And Gas Proeprties Revenue [Member]
Revenues
Revenues	$ 1,654,000	$ 1,035,000	$ 4,497,000	$ 3,383,000

XML

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating activities
Net income (loss) from continuing operations	$ 530	$ (761)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	599	658
Amortization of loan fees-interest expense	3	11
Accretion on asset retirement obligation	106	107
(Gain) loss on asset sales	(34)	(5)
Stock based compensation	4	11
Changes in assets and liabilities:
Accounts receivable	(57)	90
Inventory and other assets	(144)	110
Accounts payable	(14)	(122)
Accrued and other current liabilities	30	113
Settlement on asset retirement obligation	(5)	(21)
Net cash provided by operating activities - continuing operations	1,018	191
Net cash provided by (used in) operating activities - discontinued operations	45	23
Net cash provided by operating activities	1,063	214
Investing activities
Additions to oil and gas properties	(453)	(147)
Proceeds from sale of oil and gas properties	7	6
Additions to other property and equipment	(28)	(12)
Proceeds from sale of other property and equipment	8
Net cash used in investing activities - continuing operations	(466)	(153)
Net cash provided by investing activities - discontinued operations	2,650
Net cash provided by (used in) investing activities	2,184	(153)
Financing activities
Repayments of borrowings	(130)	(2,844)
Proceeds from borrowings	100	400
Proceeds from stock issuance in rights offering		2,699
Cost of stock issuance in rights offering		(102)
Net cash provided by (used in) financing activities - continuing operations	(30)	153
Net cash provided by (used in) financing activities - discontinued operations
Net cash provided by (used in) financing activities	(30)	153
Net change in cash and cash equivalents	3,217	214
Cash and cash equivalents, beginning of period	185	76
Cash and cash equivalents, end of period	3,402	290
Supplemental cash flow information:
Cash interest payments		25
Supplemental non-cash investing and financing activities:
Financed company vehicles, net of trade-ins	76	27
Cost of stock issuance in rights offering		(140)
Asset retirement obligations incurred		$ 1
Capital expenditures included in accounts payable and accrued liabilities	$ 227

XML

Description Of Business And Significant Accounting Policies

9 Months Ended

Sep. 30, 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 September 30, 2018 and September 30, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 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 nine months ended September 30, 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 and request them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.  When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis.  Fees and other deductions incurred prior to transfer of control are recorded as production costs.  Revenues are reported net of fees and other deductions incurred after transfer of control.

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 and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations.  (See Note 11. Discontinued Operations)

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 and nine months ended September 30, 2018 and 2017 (in thousands):

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

There were no natural gas imbalances at September 30, 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 September 30, 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 September 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 September 30, 2018 and December 31, 2017, inventory consisted of the following (in thousands):

	September 30,		December 31,
	2018		2017
Oil – carried at cost	$	541	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	646	$	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 September 30, 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.  The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2018 and 2017.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at September 30, 2018 and December 31, 2017.

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

	September 30,		December 31,
	2018		2017
Revenue	$	510	$	479
Tax		121		—
Joint interest		54		23
Other		24		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	695	$	517

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

Reclassifications

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

XML

Liquidity

9 Months Ended

Sep. 30, 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 aborrowing base of $3 million, subject to a credit limit based on current covenants of approximately $2.74 million, with no funds currently drawn.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

XML

Income Taxes

9 Months Ended

Sep. 30, 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.

The Company has computed an estimated annual effective tax rate for the current reporting year of 0% based upon the year-to-date and forecasted book income and cumulative loss position for the three year period ended December 31, 2018.  Accordingly, the Company has recorded no provision or benefit for income taxes for the current reporting period.

At December 31, 2017, federal net operating loss carryforwards amounted to approximately $34.8 million which expire between 2019 and 2036. In 2017, the Company released a portion of the valuation allowance related to the Company’s Minimum Tax Credit (“MTC”) as a result of the 2017 Tax Act.  The net total deferred tax asset of $242,000 was recorded as a non-current receivable at December 31, 2017.  At September 30, 2018, based upon its expected recovery, the Company reclassified $121,000of this tax related non-current receivable as  a  current receivable.  The Company recorded a valuation allowance on the remaining deferred tax assets at September 30, 2018 and December 31, 2017 as such amounts were not considered to be more-likely-than-not realizable due to cumulative losses incurred during the preceding 3 year period.There were no recorded unrecognized tax benefits at September 30, 2018. 

XML

Capital Stock

9 Months Ended

Sep. 30, 2018

Capital Stock [Abstract]

Capital Stock

(4) Capital Stock

Common Stock

There were no common shares issued during the three months ended September 30, 2018.

On October 1, 2018, 14,797 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 if the Company’s experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock.

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

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

9 Months Ended

Sep. 30, 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				For the Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	298	$	(361)	$	530	$	(761)
Net income from discontinued operations	$	—	$	46	$	1,120	$	55
Weighted average shares (denominator):
Weighted average shares – basic		10,624,493		10,614,402		10,624,476		9,899,696
Dilution effect of share-based compensation, treasury method		—		—		—		—
Weighted average shares – dilutive		10,624,493		10,614,402		10,624,476		9,899,696
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.03	$	(0.03)	$	0.05	$	(0.08)
Discontinued operations	$	0.00	$	0.00	$	0.11	$	0.01

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

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Recent Accounting Pronouncements

9 Months Ended

Sep. 30, 2018

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

(6)  Recent Accounting Pronouncements

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.

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Related Party Transactions

9 Months Ended

Sep. 30, 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. 

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

As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for goods and services with vendors in connection with its operation of the Hoactzin properties.  In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name.  As a result of the operations performed in late 2009 and early 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet.  Payables related to these past due and ongoing operations remained outstanding at September 30, 2018 and December 31, 2017 in the amount of $159,000.  The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2018 and December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”.  The outstanding balance of $159,000 should not increase in the future.  However, Hoactzin has not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012.  Based on these circumstances, the Company has elected to record an allowance in the amount of $159,000 for the balances outstanding at September 30, 2018 and December 31, 2017.  This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”.  The resulting balances recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at September 30, 2018 and December 31, 2017.

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Oil And Gas Properties

9 Months Ended

Sep. 30, 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):

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

The Company recorded depletion expense of $546,000 and $608,000 for the nine months ended September 30, 2018 and 2017, respectively.  During the nine months ended September 30, 2018 and 2017, the Company also recorded in “Accumulated depreciation, depletion, and amortization” an $8,000 gain on asset retirement obligations and a $2,000 gain on asset retirement obligations, respectively.

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 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 nine months ended September 30, 2018(in thousands):

Balance December 31, 2017	$	2,270
Accretion expense		106
Liabilities incurred		—
Liabilities settled		(13)
Balance September 30, 2018	$	2,363

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Long-Term Debt

9 Months Ended

Sep. 30, 2018

Long-Term Debt [Abstract]

Long-Term Debt

(10)  Long-Term Debt

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

	September 30,		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 $5		136		90
Total  long-term debt		136		90
Less current maturities		(60)		(41)
Long-term debt, less current maturities	$	76	$	49

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

On August 24, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 million.  The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.50% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million and the Company had no outstanding borrowing under the facility as of September 30, 2018.  The next borrowing base review will take place in March 2019.

On March 21, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s review of the Company’s owned producing properties was amended to increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020.  The borrowing base remained subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum.  This rate was 5.00% at the date of the amendment.  The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million.

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Discontinued Operations

9 Months Ended

Sep. 30, 2018

Discontinued Operations [Abstract]

Discontinued Operations

(11)  Discontinued Operations

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

	September 30,		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	$	—	$	27
Accrued and other current liabilities		—		16
Discontinued operations included in current liabilities	$	—	$	43
	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Revenues	$	—	$	144	$	6	$	458
Production costs and taxes		—		(82)		(40)		(356)
Depreciation, depletion, and amortization		—		(16)		(4)		(47)
Interest income		—		—		1		—
Gain on sale of assets		—		—		1,157		—
Deferred income tax benefit		—		—		—		—
Net income (loss) from discontinued operations	$	—	$	46	$	1,120	$	55

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

9 Months Ended

Sep. 30, 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 September 30, 2018 and December 31, 2017.

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Commitments And Contingencies

9 Months Ended

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

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

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

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors.  These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel.  In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors.  For the period January 1, 2015 through September 30, 2018, the reductions were approximately $445,000.  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)

9 Months Ended

Sep. 30, 2018

Description Of Business And Significant Accounting Policies [Abstract]

Basis Of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements as of September 30, 2018 and September 30, 2017 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements.  The condensed consolidated balance sheet as of December 31, 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 nine months ended September 30, 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 and request them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others.  When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis.  Fees and other deductions incurred prior to transfer of control are recorded as production costs.  Revenues are reported net of fees and other deductions incurred after transfer of control.

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 and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations.  (See Note 11. Discontinued Operations)

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 and nine months ended September 30, 2018 and 2017 (in thousands):

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

There were no natural gas imbalances at September 30, 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 September 30, 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 September 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 September 30, 2018 and December 31, 2017, inventory consisted of the following (in thousands):

	September 30,		December 31,
	2018		2017
Oil – carried at cost	$	541	$	436
Equipment and materials – carried at market		105		105
Total inventory	$	646	$	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 September 30, 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.  The Company did not record any impairment of its oil and gas properties during the nine months ended September 30, 2018 and 2017.

Accounts Receivable

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production and within 60 days of sales of produced electricity, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied first to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at September 30, 2018 and December 31, 2017.

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

	September 30,		December 31,
	2018		2017
Revenue	$	510	$	479
Tax		121		—
Joint interest		54		23
Other		24		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	695	$	517

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

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)

9 Months Ended

Sep. 30, 2018

Description Of Business And Significant Accounting Policies [Abstract]

Disaggregation Of Revenue

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

Inventory

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

Accounts Receivable

	September 30,		December 31,
	2018		2017
Revenue	$	510	$	479
Tax		121		—
Joint interest		54		23
Other		24		29
Allowance for doubtful accounts		(14)		(14)
Total accounts receivable	$	695	$	517

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Earnings Per Common Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Common Share [Abstract]

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

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Income (numerator):
Net income (loss) from continuing operations	$	298	$	(361)	$	530	$	(761)
Net income from discontinued operations	$	—	$	46	$	1,120	$	55
Weighted average shares (denominator):
Weighted average shares – basic		10,624,493		10,614,402		10,624,476		9,899,696
Dilution effect of share-based compensation, treasury method		—		—		—		—
Weighted average shares – dilutive		10,624,493		10,614,402		10,624,476		9,899,696
Income (loss) per share – Basic and Dilutive:
Continuing operations	$	0.03	$	(0.03)	$	0.05	$	(0.08)
Discontinued operations	$	0.00	$	0.00	$	0.11	$	0.01

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Oil And Gas Properties (Tables)

9 Months Ended

Sep. 30, 2018

Oil And Gas Properties [Abstract]

Schedule Of Oil And Gas Properties

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

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Transactions

Balance December 31, 2017	$	2,270
Accretion expense		106
Liabilities incurred		—
Liabilities settled		(13)
Balance September 30, 2018	$	2,363

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2018

Long-Term Debt [Abstract]

Schedule Of Long-term Debt To Unrelated Entites

	September 30,		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 $5		136		90
Total  long-term debt		136		90
Less current maturities		(60)		(41)
Long-term debt, less current maturities	$	76	$	49

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2018

Discontinued Operations [Abstract]

Schedule Of The Amounts In Net Loss From Discontinued Operations

	September 30,		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	$	—	$	27
Accrued and other current liabilities		—		16
Discontinued operations included in current liabilities	$	—	$	43
	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Revenues	$	—	$	144	$	6	$	458
Production costs and taxes		—		(82)		(40)		(356)
Depreciation, depletion, and amortization		—		(16)		(4)		(47)
Interest income		—		—		1		—
Gain on sale of assets		—		—		1,157		—
Deferred income tax benefit		—		—		—		—
Net income (loss) from discontinued operations	$	—	$	46	$	1,120	$	55

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Description Of Business And Significant Accounting Policies (Narrative) (Details) - USD ($)		1 Months Ended	9 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Description Of Business And Significant Accounting Policies [Line Items]
Material natural gas imbalances			$ 0		$ 0
Unevaluated properties			0		0
Impairment			0	$ 0
Sale of methane facility assets	$ 2,650,000	$ 2,650,000
Accounts receivable			695,000		517,000
Accounts receivable - noncurrent			121,000		$ 242,000
Restatement Adjustment [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Accounts receivable			$ 121,000

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Description Of Business And Significant Accounting Policies (Disaggregation Of Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 1,654	$ 1,035	$ 4,497	$ 3,383
Crude Oil [Member]
Disaggregation of Revenue [Line Items]
Revenues	1,647	1,028	4,472	3,360
Salt Water Disposal Fees [Member]
Disaggregation of Revenue [Line Items]
Revenues	$ 7	$ 7	$ 25	$ 23

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Description Of Business And Significant Accounting Policies (Inventory) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Description Of Business And Significant Accounting Policies [Abstract]
Oil - carried at cost	$ 541	$ 436
Equipment and materials - carried at market	105	105
Total inventory	$ 646	$ 541

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Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (14)	$ (14)
Total accounts receivable	695	517
Revenue [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	510	479
Tax [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	121
Joint Interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	54	23
Other [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 24	$ 29

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Liquidity (Narrative) (Details) - USD ($)		1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Aug. 24, 2018	Mar. 21, 2018
Liquidity [Line Items]
Net loss from operations			$ 298,000	$ (315,000)	$ 1,650,000	$ (706,000)	$ (574,000)
Credit facility current borrowing capacity			3,000,000		3,000,000			$ 3,000,000
Credit facility maximum borrowing capacity			2,740,000		2,740,000			$ 2,740,000
Sale of methane facility assets	$ 2,650,000	$ 2,650,000
Prosperity Bank [Member]
Liquidity [Line Items]
Credit facility current borrowing capacity			3,000,000		3,000,000
Current funds drawn			0		0
Credit facility maximum borrowing capacity			$ 50,000,000		$ 50,000,000				$ 2,000,000

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Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Income Taxes [Line Items]
Provision or benefit for income taxes
Unrecognized tax benefits	0		$ 0
Federal net operating loss carryforwards					$ 34,800,000
Estimated annual effective tax rate			0.00%
Accounts receivable	695,000		$ 695,000		$ 517,000
Restatement Adjustment [Member]
Income Taxes [Line Items]
Accounts receivable	$ 121,000		$ 121,000
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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Capital Stock (Narrative) (Details)			3 Months Ended	9 Months Ended
	Oct. 01, 2018 shares	Mar. 17, 2017 $ / shares	Sep. 30, 2018 $ / shares shares	Sep. 30, 2018 $ / shares shares	Dec. 31, 2017 $ / shares shares	Mar. 16, 2017 $ / shares
Capital Stock [Line Items]
Common stock, New shares issued			0
Common stock, par value | $ / shares			$ 0.001	$ 0.001	$ 0.001
Preferred stock, shares authorized			25,000,000	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] | Subsequent Event [Member]
Capital Stock [Line Items]
Common stock, New shares issued	14,797
Series A Preferred Stock [Member]
Capital Stock [Line Items]
Preferred stock, shares authorized			10,000	10,000	10,000
Preferred stock, par value | $ / shares			$ 0.0001	$ 0.0001	$ 0.0001
Preferred stock, shares issued			0	0	0
Series A Preferred Stock [Member] | Rights Plan [Member]
Capital Stock [Line Items]
Preferred stock, shares issued			0	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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Common Share [Abstract]
Net income (loss) from continuing operations	$ 298	$ (361)	$ 530	$ (761)
Net income from discontinued operations		$ 46	$ 1,120	$ 55
Weighted average shares - basic	10,624,493	10,614,402	10,624,476	9,899,696
Dilution effect of share-based compensation, treasury method
Weighted average shares - dilutive	10,624,493	10,614,402	10,624,476	9,899,696
Continuing operations	$ 0.03	$ (0.03)	$ 0.05	$ (0.08)
Discontinued operations	$ 0.00	$ 0.00	$ 0.11	$ 0.01

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Related Party Transactions (Narrative) (Details) - USD ($)	Dec. 18, 2007	Sep. 30, 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
Accounts receivable - related parties balance
Hoactzin Partners, L.P. [Member]
Related Party Transaction [Line Items]
Related parties accounts payable		159,000	159,000
Past due related parties accounts payable		159,000
Related Party [Member]
Related Party Transaction [Line Items]
Related party allowance for doubtful accounts receivable		159,000	159,000
Related Party [Member] | Hoactzin Partners, L.P. [Member]
Related Party Transaction [Line Items]
Accounts receivable-related party, allowance for doubtful accounts		159,000	159,000
Accounts receivable - related parties balance		$ 159,000	$ 0

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Oil And Gas Properties (Narrative) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Oil And Gas Properties [Abstract]
Depletion expense	$ 546,000	$ 608,000
Gain on asset retirement obligations	$ 8,000	$ 2,000

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Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Oil And Gas Properties [Abstract]
Oil and gas properties	$ 6,377	$ 5,704
Unevaluated properties
Accumulated depreciation, depletion, and amortization	(1,538)	(984)
Oil and gas properties, net	$ 4,839	$ 4,720

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Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Asset Retirement Obligation [Abstract]
Balance	$ 2,270
Accretion expense	106	$ 107
Liabilities incurred
Liabilities settled	(13)
Balance	$ 2,363

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Long-Term Debt (Narrative) (Details)			9 Months Ended
	Aug. 24, 2018 USD ($)	Mar. 21, 2018 USD ($)	Sep. 30, 2018 USD ($)
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 2,740,000		$ 2,740,000
Credit facility current borrowing capacity	$ 3,000,000		3,000,000
Credit limit			$ 2,740,000
Prosperity Bank [Member]
Debt Instrument [Line Items]
Credit facility maturity date			Jul. 31, 2020
Rate above prime	0.50%	0.50%
Interest rate	5.50%	5.00%	5.75%
Credit facility maximum borrowing capacity		$ 2,000,000	$ 50,000,000
Credit facility current borrowing capacity			3,000,000
Credit facility amount outstanding			0
Prosperity Bank [Member] | Loans And Letters Of Credit [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 50,000,000
Maximum [Member] | Prosperity Bank [Member]
Debt Instrument [Line Items]
Funded debt to EBITDA			3.5
Minimum [Member] | Prosperity Bank [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	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Note payable to a financial institution, with interest only payment until maturity
Installment notes bearing interest at the rate of 4.16% to 4.60% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $5	136	90
Total long-term debt	136	90
Less current maturities	(60)	(41)
Long-term debt, less current maturities	76	$ 49
Periodic payments including interest, insurance and maintenance	$ 5
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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Discontinued Operations (Schedule Of The Amounts In Net Loss From Discontinued Operations) (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended	9 Months Ended
	Jan. 26, 2018	Jan. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 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						43
Net income (loss) from discontinued operations			$ 46	$ 1,120	$ 55
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						27
Accrued and other current liabilities						16
Discontinued operations included in current liabilities						$ 43
Revenues			144	6	458
Production costs and taxes			(82)	(40)	(356)
Depreciation, depletion, and amortization			(16)	(4)	(47)
Interest income				1
Gain on sale of assets				1,157
Net income (loss) from discontinued operations			$ 46	$ 1,120	$ 55

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Commitments And Contingencies (Narrative) (Details)	1 Months Ended	9 Months Ended	45 Months Ended
	Oct. 31, 2018 USD ($)	Sep. 30, 2018 USD ($) $ / bbl	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2012 USD ($)
Loss Contingencies [Line Items]
Decrease in compensation			$ 445,000
Period of trailing average of WTI		30 days
Drilling and seismic commitment		$ 131,000	$ 131,000
Seismic commitment				$ 32,000
Incidence Of Non-Compliance [Member]
Loss Contingencies [Line Items]
Maximum potential loss					$ 386,000
Subsequent Event [Member]
Loss Contingencies [Line Items]
Cost incurred, development costs	$ 69,000
Minimum [Member]
Loss Contingencies [Line Items]
Compensation reduction until WTI posting | $ / bbl		70
Compensation reimbursement at WTI posting | $ / bbl		85