Riley Exploration Permian (REPX) 10-Q 14 Nov 16 2016 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 07, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Entity Registrant Name	TENGASCO INC
Entity Central Index Key	1,001,614
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		6,097,723

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current
Cash and cash equivalents	$ 31	$ 40
Accounts receivable, less allowance for doubtful accounts of $14	490	446
Accounts receivable - related party, less allowance for doubtful accounts of $159
Inventory	632	542
Other current assets	172	354
Total current assets	1,325	1,382
Oil and gas properties, net (full cost accounting method)	5,594	8,838
Manufactured Methane facilities, net	1,563	1,573
Other property and equipment, net	156	200
Total assets	8,638	11,993
Current liabilities
Accounts payable - trade	188	151
Accounts payable - other	159	159
Accounts payable - related party		634
Accrued and other current liabilities	226	356
Current maturities of long-term debt	58	65
Total current liabilities	631	1,365
Asset retirement obligation	2,243	2,222
Long term debt, less current maturities	2,231	946
Total liabilities	5,105	4,533
Commitments and contingencies (Note 11)
Stockholders' equity
Common stock, $.001 par value, authorized 100,000,000 shares, 6,093,634 and 6,084,241 shares issued and outstanding	6	6
Additional paid-in capital	55,782	55,770
Accumulated deficit	(52,255)	(48,316)
Total stockholders' equity	3,533	7,460
Total liabilities and stockholders' equity	$ 8,638	$ 11,993

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 14	$ 14
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	6,093,634	6,084,241
Common stock, shares outstanding	6,093,634	6,084,241
Related Party [Member]
Allowance for doubtful accounts	$ 159	$ 159

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues
Oil and gas properties	$ 1,070,000	$ 1,275,000	$ 2,965,000	$ 4,545,000
Methane facility	172,000	150,000	491,000	413,000
Total revenues	1,242,000	1,425,000	3,456,000	4,958,000
Cost and expenses
Production costs and taxes	889,000	1,128,000	2,570,000	3,223,000
Depreciation, depletion, and amortization	256,000	647,000	904,000	2,082,000
General and administrative	346,000	585,000	1,131,000	1,557,000
Impairment	632,000	7,189,000	2,718,000	7,189,000
Total cost and expenses	2,123,000	9,549,000	7,323,000	14,051,000
Net loss from operations	(881,000)	(8,124,000)	(3,867,000)	(9,093,000)
Other expenses
Interest expense	(27,000)	(47,000)	(73,000)	(70,000)
Gain on sale of assets		17,000	1,000	38,000
Total other expenses	(27,000)	(30,000)	(72,000)	(32,000)
Loss from operations before income tax	(908,000)	(8,154,000)	(3,939,000)	(9,125,000)
Deferred Income tax benefit		3,191,000	0	3,572,000
Net loss	$ (908,000)	$ (4,963,000)	$ (3,939,000)	$ (5,553,000)
Net loss per share
Basic	$ (0.15)	$ (0.82)	$ (0.65)	$ (0.91)
Fully Diluted	$ (0.15)	$ (0.82)	$ (0.65)	$ (0.91)
Shares used in computing earnings per share
Basic	6,093,579	6,084,241	6,088,834	6,084,241
Diluted	6,093,579	6,084,241	6,088,834	6,084,241

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities
Net loss from operations	$ (3,939,000)	$ (5,553,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	904,000	2,082,000
Amortization of loan fees-interest expense	5,000	8,000
Accretion on asset retirement obligation	107,000	94,000
Impairment	2,718,000	7,189,000
Gain on sale of assets		(38,000)
Stock based compensation	12,000	9,000
Deferred tax expense (benefit)		(3,572,000)
Changes in assets and liabilities:
Accounts receivable	(45,000)	282,000
Inventory and other assets	92,000	300,000
Accounts payable	(597,000)	(2,000)
Accrued and other current liabilities	(130,000)	(433,000)
Settlement on asset retirement obligation	(66,000)	(17,000)
Net cash provided by (used in) operating activities	(939,000)	349,000
Investing activities
Additions to oil and gas properties	(300,000)	(566,000)
Additions to methane project	(35,000)
Additions to other property and equipment	(5,000)	(1,000)
Proceeds from sale of other property and equipment	4,000	31,000
Net cash used in investing activities	(336,000)	(536,000)
Financing activities
Repayments of borrowings	(1,974,000)	(3,273,000)
Proceeds from borrowings	3,250,000	3,500,000
Loan fees	(10,000)	(2,000)
Net cash provided by financing activities	1,266,000	225,000
Net change in cash and cash equivalents	(9,000)	38,000
Cash and cash equivalents, beginning of period	40,000	35,000
Cash and cash equivalents, end of period	31,000	73,000
Supplemental cash flow information:
Cash interest payments	68,000	18,000
Supplemental non-cash investing and financing activities:
Financed company vehicles	$ 23,000	$ 117,000

Description Of Business And Sig

Description Of Business And Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Description Of Business And Significant Accounting Policies [Abstract]
Description Of Business And Significant Accounting Policies	(1) D escription 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, Manufactured Methane Corporation (“MMC”) operates a treatment facility for the extraction of methane gas from nonconventional sources for eventual sale to natural gas customers or generation of electricity. This facility is located at the Carter Valley landfill site in Church Hill, Tennessee.  Basis of Presentation  The accompanying unaudited condensed consolidated financial statements 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, although 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, 2016 are not necessarily indicative of the results that may be expected for the year ended December 31, 2016. 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, 2015.  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 consolidated financial statements are prepared in conformity with U.S. GAAP which requires 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 impairment 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 other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.  Revenue Recognition  Revenues are recognized based on actual volumes of oil, natural gas, methane, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized. There were no natural gas imbalances at September 30, 2016 or December 31, 2015. Methane gas and electricity sales meters are located at the Carter Valley landfill site and any sales of methane or electricity are billed each month. No methane gas was sold during the nine months ended September 30, 2016 or 2015.  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, 2016 and December 31, 2015. These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost. The market component is calculated using the average September 2016 and December 2015 oil sales prices received from the Company’s Kansas properties. In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or 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 as of September 30, 2016 and December 31, 2015. The following table sets forth information concerning the Company’s inventory (in thousands) :      September 30, December 31,  2016 2015  Oil – carried at market $ 422 $ 332  Equipment and materials – carried at market 210 210  Total inventory $ 632 $ 542  Full Cost Method of Accounting  The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had unevaluated properties of $552,000 at September 30, 2016 and December 31, 2015. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.  At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down cannot be reversed in a later period. During the three months and nine months ended September 30, 2016, the Company recorded an impairment of oil and gas properties in the amount of $632,000 and $2,718,000 , respectively. During the three months and nine months ended September 30, 2015, the Company recorded an impairment of oil and gas properties in the amount of $7,189,000 .  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 production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied 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, 2016 and December 31, 2015.  The following table sets forth information concerning the Company’s accounts receivable (in thousands) :      September 30, December 31,  2016 2015  Revenue $ 462 $ 417  Joint interest 21 21  Other 21 22  Allowance for doubtful accounts (14) (14)  Total accounts receivable $ 490 $ 446

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Taxes [Abstract]
Income Taxes	(2) Income Taxes  The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.  The deferred income tax assets or liabilities for an oil and gas exploration and development company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the asset or liability is subject to continuous recalculation, and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.  The Company does not expect to pay any federal or state income tax for the year 2016 as a result of an anticipated net loss during 2016 . Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some or all of the benefits of deferred tax assets will not be realized. As of September 30, 2016, the Company has recorded a full valuation allowance on its deferred tax assets. Based on these requirements, no provision or benefit for income taxes has been recorded for deferred taxes. There were no recorded unrecognized tax benefits at September 30, 2016.

Earnings Per Common Share

Earnings Per Common Share	9 Months Ended
	Sep. 30, 2016
Earnings Per Common Share [Abstract]
Earnings Per Common Share	(3) 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,  2016 2015 2016 2015  Loss (numerator):  Net loss $ (908) $ (4,963) $ (3,939) $ (5,553)  Weighted average shares (denominator):  Weighted average shares – basic 6,093,579 6,084,241 6,088,834 6,084,241  Dilution effect of share-based compensation, treasury method — — — —  Weighted average shares – dilutive 6,093,579 6,084,241 6,088,834 6,084,241  Loss per share – Basic and Dilutive:  Basic $ (0.15) $ (0.82) $ (0.65) $ (0.91)  Dilutive $ (0.15) $ (0.82) $ (0.65) $ (0.91) Share and per share data at September 30, 2015 has been adjusted to reflect the impact of the 1 for 10 reverse stock split approved at the shareholder meeting on March 21, 2016, effective with trading on March 24, 2016. The total number of shares issued and outstanding represent estimates after adjustments to reflect the impact of the reverse stock split.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2016
Recent Accounting Pronouncements [Abstract]
Recent Accounting Pronouncements	(4) Recent Accounting Pronouncements  In August 2014, the FASB issued Update No. 2014-15— Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This was issued to provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. T he guidance is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016. Early application is permitted. The Company does not expect this to impact its operating results or cash flows.  In November 2015, the FASB issued ASU 2015-17 Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This guidance eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The amendments may be applied prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company does not expect this to impact its operating results or cash flows.  In February 2016, the FASB issued Update 2016-02— Leases (Topic 842). This guidance was issued to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This guidance is e ffective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this Update is permitted for all entities. The Company does not expect this to impact its operating results or cash flows.  In March 2016, the FASB issued Update 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. This guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This guidance is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The Company does not expect this to impact operating results or cash flows.  In August 2016, the FASB issued Update 2016- 15 Statement of Cash Flows (Topic 230 ): Classification of Certain Cash Receipts and Cash Payments . This amendment provides guidance on certain cash flow classification issues, thereby reducing the current and potential future diversity in practice . This guidance is effective for annual periods beginning after December 15, 201 7 , and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The Company does not expect this to impact operating results or cash flows. 

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	(5) Related Party Transactions  On September 17, 2007, the Company entered into a drilling program with Hoactzin Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Ten Well Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He was also at the time the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which was the Company’s largest shareholder at that time.  Under the terms of the Ten Well Program, Hoactzin paid the Company $0.4 million for each well drilled in the Ten Well Program completed as a producing well and $0.25 million for each well that was non-productive. The terms of the Ten Well Program also provided that Hoactzin would receive all the working interest in the ten wells in the Program, but would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but, as defined, is in the nature of a net profits interest. The fee paid to the Company by Hoactzin would increase to 85% if net revenues received by Hoactzin reached an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”) for its interest in the Ten Well Program.  In March 2008, the Company drilled and completed the final well in the Ten Well Program. Hoactzin paid a total of $3.85 million (the “Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being determined as $5.2 million.  On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, was conveyed a 75% net profits interest in the methane extraction project developed by MMC at the Carter Valley landfill owned by Republic Services in Church Hill, Tennessee (the "Methane Project"). Net profits, if any, from the Methane Project received by Hoactzin would have been applied towards the determination of the Payout Point for the Ten Well Program. However, through September 30 , 2016, no payments were made to Hoactzin for its net profits interest in the Methane Project, because no net profits were generated.  The method of calculation of the net profits interest takes into account specific costs and expenses as well as gross gas revenues for the Methane Project. As a result of the startup costs and ongoing operating expenses, no net profits, as defined in the agreement, have been generated from startup in April, 2009 through September 30, 2016 for payment to Hoactzin under the net profits interest conveyed.  In February 2014, net revenues earned by Hoactzin from the Ten Well Program had exceeded $5.2 million and thereby reached the Payout Point which increased the management fee due to the Company by Hoactzin from 25% to 85% and reduced the net profits interest in the Methane Project from 75% to 7.5% .  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, offshore Texas, and offshore Louisiana (the “Management Agreement”).  The Management Agreement terminated by its own terms on December 18, 2012. The Company is assisting Hoactzin with becoming operator of record of these wells. The Company has entered into a transition agreement with Hoactzin whereby Hoactzin and its controlling member indemnify the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of record on certain of these wells.  During the course of the Management Agreement, the Company became the operator of certain properties owned by Hoactzin. The Company obtained from IndemCo, over time, bonds in the face amount of approximately $10.7 million for the purpose of covering plugging and abandonment obligations for Hoactzin’s operated properties located in federal offshore waters in favor of the BSEE, as well as certain private parties. In connection with the issuance of these bonds the Company signed a Payment and Indemnity Agreement with IndemCo whereby the Company guaranteed payment of any bonding liabilities incurred by IndemCo. Hoactzin had provided $6.6 million in cash to IndemCo as collateral for these potential obligations. As of May 15, 2014, all bonds issued by IndemCo and subject to the Payment and Indemnity Agreement have been released by the BSEE and have been cancelled by IndemCo. Accordingly, the exposure to the Company under any of the now cancelled IndemCo bonds or the indemnity agreement relating to those now cancelled bonds has decreased to zero .  As part of the transition process, Hoactzin secured new bonds from Argonaut Insurance Company to replace the IndemCo bonds. As noted above, all of the IndemCo bonds were replaced, and all IndemCo bonds were cancelled. Also as part of the transition to Hoactzin becoming named operator of its own properties, four separate right-of-use and easement (“RUE”) bonds in the aggregate amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as then-current operator. As of September 30, 2016 , all of these four RUE bonds have been cancelled and released by the Bureau of Ocean Energy Management as to the Company. Accordingly, the transfer from the Company to Hoactzin of all interests in and obligations under these four RUE’s and associated bonding is completed.  As operator, 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. During late 2009 and early 2010, Hoactzin undertook several significant operations, for which the Company contracted in the ordinary course. 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, 2016 and December 31, 2015 in the amount of $159,000 . The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of September 30, 2016 and December 31, 2015 in its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable – related party”. 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 establish an allowance in the amount of $159,000 for the balances outstanding at September 30, 2016 and December 31, 2015. This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”. The resulting balance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” is $0 at September 30, 2016 and December 31, 2015.  The Company has entered into an agreement with Hoactzin whereby Hoactzin and Dolphin Direct are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is still the operator of record on certain of these wells. Until such time as Hoactzin becomes operator of record on these wells and the corresponding bonding liability is transferred from the Company to Hoactzin, per the transition agreement, the Company had suspended drilling payments to Hoactzin. As of December 31, 2015, the Company had suspended approximately $634,000 in payments. This balance of these suspended payments is recorded in the Consolidated Balance Sheet under “Accounts payable – related party”. In January 2016, the Company paid these held funds to Hoactzin.  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 collateralize the appeal bond with RLI Insurance Company and to pay the civil penalty and interest thereon. See Note 11 Commitments and Contingencies.

Oil And Gas Properties

Oil And Gas Properties	9 Months Ended
	Sep. 30, 2016
Oil And Gas Properties [Abstract]
Oil And Gas Properties	(6) Oil and Gas Properties  The following table sets forth information concerning the Company’s oil and gas properties (in thousands) :      September 30, December 31,  2016 2015  Oil and gas properties, at cost $ 5,042 $ 8,286  Unevaluated properties 552 552  Oil and gas properties $ 5,594 $ 8,838  The Company recorded depletion expense of $806,000 and $1,974,000 for the nine months ended September 30, 2016 and 2015, respectively. In addition, during the nine months ended September 30, 2016 and 2015 , the Company recorded an impairment of oil and gas properties in the amount of $2,718,000 and $7,189,000 , respectively . As a result of the ceiling test impairment, the accumulated depreciation, depletion, and amortization has been netted against the cost to reflect the post impairment value of the oil and gas properties.

Asset Retirement Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	(7) 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, 2016 (in thousands) :      Balance December 31, 2015 $ 2,222  Accretion expense 107  Liabilities incurred —  Liabilities settled (86)  Balance September 30, 2016 $ 2,243

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Long-Term Debt [Abstract]
Long-Term Debt	(8) Long-Term Debt  Long-term debt to unrelated entities consisted of the following (in thousands) :      September 30, December 31,  2016 2015  Note payable to a financial institution, with interest only payment until maturity. $ 2,187 $ 869  Less unamortized debt issuance cost (15) (10)  Note payable to a financial institution, net of unamortized debt issuance cost 2,172 859   Installment notes bearing interest at the rate of 4.16% to 4.6% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 117 152  Total long-term debt 2,289 1,011  Less current maturities (58) (65)  Long-term debt, less current maturities $ 2,231 $ 946  Unamortized debt issuance cost at December 31, 2015 was reclassified from an asset to a reduction of long-term debt. This reclassification was done to comply with ASU 2015-03 Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost.  On March 28, 2016, 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 decrease the Company’s borrowing base from $7.8 million to approximately $3.2 million, extend the term of the facility to January 30, 2018 , and delete the Leverage Ratio covenant. For the quarter ended December 31, 2015, the Company was in default on compliance with the Leverage Ratio covenant. In addition, the amendment also added a Debt to Tangible Net Worth covenant, waived the default on the Interest Coverage ratio for the quarter ended December 31, 2015, waived the anticipated default for the quarter ended March 31, 2016, and waived compliance with the Interest Coverage ratio for all applicable periods through the maturity date. Although the Company was in default of the Leverage and Interest Coverage ratios for the quarter ended December 31, 2015, the Company was in compliance at March 28, 2016 as a result of the amendment and waivers. For the quarter ended June 30, 2016, the Company was in default on compliance with the Debt to Tangible Net Worth covenant. On August 10, 2016, the Company received a waiver of the covenant default for the quarter ended June 30, 2016 as well as a waiver for the anticipated default for the quarter ended September 30, 2016. On October 17, 2016 , the Company filed a registration statement with the Securities and Exchange Commission on Form S-1 with respect to a proposed rights offering to existing shareholders . The Company anticipates that the net proceeds of the rights offering will be used initially to pay bank indebtedness. Based on this rights offering, it is anticipate d that the Company will be in compliance with the Debt to Tangible Net Worth covenant for the quarter ended December 31, 2016 and will also result in the Company having additional borrowing capacity to fund daily operations . If the Company is not successful raising equity through the rights offering, it could have a material effect on the ability to fund operations and the Company may then need to seek other sources of financing. Although the Company was in default of the Debt to Tangible Net Worth covenant for the quarter ended June 30, 2016, the Company was in compliance as of August 10, 2016 as a result of the waiver. As a result of the waivers received on default of both the Interest Coverage ratio and the Debt to Tangible Net Worth ratio, the Company was in compliance with both of these covenants at September 30, 2016. The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remain s prime plus 0.50% per annum. This rate was 4.00% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remain s $40 million. The next borrowing base review will take place in November 2016.

Manufactured Methane

Manufactured Methane	9 Months Ended
	Sep. 30, 2016
Manufactured Methane [Abstract]
Manufactured Methane	(9) Manufactured Methane  The following table sets forth information concerning the Manufactured Methane facilities (in thousands):      September 30, December 31,  2016 2015  Manufactured Methane facilities, at cost $ 1,669 $ 1,633  Accumulated depreciation (106) (60)  Manufactured Methane facilities, net $ 1,563 $ 1,573  The methane facilities were placed into service on April 1, 2009 . The methane facilities are being depreciated over the estimated useful life of approximately 33 years based on estimated landfill closure date of December 2041 . The Company recorded depreciation expense of $46,000 and $45,000 for the nine months ended September 30, 2016 and 2015 , respectively .

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Measurements [Abstract]
Fair Value Measurements	(10) 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, 2016 and December 31, 2015.

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments And Contingencies [Abstract]
Commitments And Contingencies	(11) Commitments and Contingencies  The Company as designated operator was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s properties. This action call ed 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. In the 4th quarter of 2012, the Company filed an administrative appeal with the Interior Board of Land Appeals (“IBLA”) of this action in order to attempt to significantly reduce the civil penalty. This appeal required a fully collateralized appeal bond to postpone the payment obligation until the appeal was determined. The Company posted and collateralized this bond with RLI Insurance Company. If the bond was not posted, the order to the Company to pay the $386,000 penalty would have become final. On June 23, 2014, the IBLA affirmed the civil penalty without reduction. On September 22, 2014, the Company sought judicial review of the June 23, 2014 agency action in the federal district court in the Eastern District of Louisiana at New Orleans. On July 14, 2015, the court affirmed the determination by the IBLA without reduction. The Company determined that further appeal of the determination was not likely to reduce the penalty and the Company did not further appeal. In the third quarter of 2015, the Company paid the civil penalty affirmed on appeal and statutory interest thereon from funds borrowed under its credit facility. The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty and interest thereon.  During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement. This analysis raised issues other than the “Incident of Non-Compliance” discussed above. The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis.  Cost Reduction Measures  Commencing in the quarter ended March 31, 2015 and continuing through the quarter ended September 30, 2016, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions will remain in place until such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when compensation shall revert to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. As of September 30, 2016, the reductions were approximately $205,000 . The Company has not accrued any liabilities associated with these compensation reductions.

Description Of Business And S17

Description Of Business And Significant Accounting Policies (Policy)	9 Months Ended
	Sep. 30, 2016
Description Of Business And Significant Accounting Policies [Abstract]
Basis Of Presentation	Basis of Presentation  The accompanying unaudited condensed consolidated financial statements 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, although 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, 2016 are not necessarily indicative of the results that may be expected for the year ended December 31, 2016. 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, 2015.
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 consolidated financial statements are prepared in conformity with U.S. GAAP which requires 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 impairment 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 other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Revenue Recognition	Revenue Recognition  Revenues are recognized based on actual volumes of oil, natural gas, methane, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized. There were no natural gas imbalances at September 30, 2016 or December 31, 2015. Methane gas and electricity sales meters are located at the Carter Valley landfill site and any sales of methane or electricity are billed each month. No methane gas was sold during the nine months ended September 30, 2016 or 2015.
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, 2016 and December 31, 2015. These costs include production costs and taxes, allocated general and administrative costs, depreciation, and allocated interest cost. The market component is calculated using the average September 2016 and December 2015 oil sales prices received from the Company’s Kansas properties. In addition, the Company also carries equipment and materials in inventory to be used in its Kansas operation which are carried at the lower of cost or 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 as of September 30, 2016 and December 31, 2015. The following table sets forth information concerning the Company’s inventory (in thousands) :      September 30, December 31,  2016 2015  Oil – carried at market $ 422 $ 332  Equipment and materials – carried at market 210 210  Total inventory $ 632 $ 542 
Full Cost Method Of Accounting	Full Cost Method of Accounting  The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition costs, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had unevaluated properties of $552,000 at September 30, 2016 and December 31, 2015. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.  At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down cannot be reversed in a later period. During the three months and nine months ended September 30, 2016, the Company recorded an impairment of oil and gas properties in the amount of $632,000 and $2,718,000 , respectively. During the three months and nine months ended September 30, 2015, the Company recorded an impairment of oil and gas properties in the amount of $7,189,000 .
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 production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied 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, 2016 and December 31, 2015.  The following table sets forth information concerning the Company’s accounts receivable (in thousands) :      September 30, December 31,  2016 2015  Revenue $ 462 $ 417  Joint interest 21 21  Other 21 22  Allowance for doubtful accounts (14) (14)  Total accounts receivable $ 490 $ 446

Description Of Business And S18

Description Of Business And Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2016
Description Of Business And Significant Accounting Policies [Abstract]
Inventory	   September 30, December 31,  2016 2015  Oil – carried at market $ 422 $ 332  Equipment and materials – carried at market 210 210  Total inventory $ 632 $ 542 
Accounts Receivable	   September 30, December 31,  2016 2015  Revenue $ 462 $ 417  Joint interest 21 21  Other 21 22  Allowance for doubtful accounts (14) (14)  Total accounts receivable $ 490 $ 446 

Earnings Per Common Share (Tabl

Earnings Per Common Share (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings Per Common Share [Abstract]
Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share	   For the Three Months Ended For the Nine Months Ended  September 30, September 30,  2016 2015 2016 2015  Loss (numerator):  Net loss $ (908) $ (4,963) $ (3,939) $ (5,553)  Weighted average shares (denominator):  Weighted average shares – basic 6,093,579 6,084,241 6,088,834 6,084,241  Dilution effect of share-based compensation, treasury method — — — —  Weighted average shares – dilutive 6,093,579 6,084,241 6,088,834 6,084,241  Loss per share – Basic and Dilutive:  Basic $ (0.15) $ (0.82) $ (0.65) $ (0.91)  Dilutive $ (0.15) $ (0.82) $ (0.65) $ (0.91) 

Oil And Gas Properties (Tables)

Oil And Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2016
Oil And Gas Properties [Abstract]
Schedule Of Oil And Gas Properties	   September 30, December 31,  2016 2015  Oil and gas properties, at cost $ 5,042 $ 8,286  Unevaluated properties 552 552  Oil and gas properties $ 5,594 $ 8,838 

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation Transactions	   Balance December 31, 2015 $ 2,222  Accretion expense 107  Liabilities incurred —  Liabilities settled (86)  Balance September 30, 2016 $ 2,243 

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Long-Term Debt [Abstract]
Schedule Of Long-Term Debt To Unrelated Entities	   September 30, December 31,  2016 2015  Note payable to a financial institution, with interest only payment until maturity. $ 2,187 $ 869  Less unamortized debt issuance cost (15) (10)  Note payable to a financial institution, net of unamortized debt issuance cost 2,172 859   Installment notes bearing interest at the rate of 4.16% to 4.6% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10 117 152  Total long-term debt 2,289 1,011  Less current maturities (58) (65)  Long-term debt, less current maturities $ 2,231 $ 946 

Manufactured Methane (Tables)

Manufactured Methane (Tables)	9 Months Ended
	Sep. 30, 2016
Manufactured Methane [Abstract]
Methane Facilities	   September 30, December 31,  2016 2015  Manufactured Methane facilities, at cost $ 1,669 $ 1,633  Accumulated depreciation (106) (60)  Manufactured Methane facilities, net $ 1,563 $ 1,573 

Description Of Business And S24

Description Of Business And Significant Accounting Policies (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Description Of Business And Significant Accounting Policies [Abstract]
Material natural gas imbalances	$ 0		$ 0		$ 0
Methane gas revenue			0	$ 0
Unevaluated properties	552,000		$ 552,000		$ 552,000
Current cost discount			10.00%
Impairment	$ 632,000	$ 7,189,000	$ 2,718,000	$ 7,189,000

Description Of Business And S25

Description Of Business And Significant Accounting Policies (Inventory) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Description Of Business And Significant Accounting Policies [Abstract]
Oil - carried at market	$ 422	$ 332
Equipment and materials - carried at market	210	210
Total inventory	$ 632	$ 542

Description Of Business And S26

Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (14)	$ (14)
Total accounts receivable	490	446
Revenue [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	462	417
Joint Interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	21	21
Other [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 21	$ 22

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Taxes [Abstract]
Provision or benefit for income taxes	$ (3,191,000)	$ 0	$ (3,572,000)
Unrecognized tax benefits		$ 0

Earnings Per Common Share (Reco

Earnings Per Common Share (Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share) (Details) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares
Earnings Per Common Share [Abstract]
Net loss | $	$ (908)	$ (4,963)	$ (3,939)	$ (5,553)
Weighted average shares - basic	6,093,579	6,084,241	6,088,834	6,084,241
Dilution effect of share-based compensation, treasury method
Weighted average shares - dilutive	6,093,579	6,084,241	6,088,834	6,084,241
Basic | $ / shares	$ (0.15)	$ (0.82)	$ (0.65)	$ (0.91)
Dilutive | $ / shares	$ (0.15)	$ (0.82)	$ (0.65)	$ (0.91)
Reverse stock split			0.1

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Details)	Sep. 17, 2007USD ($)item	Feb. 28, 2014	Jan. 31, 2014	Sep. 30, 2016USD ($)	Dec. 31, 2015USD ($)	May 15, 2014USD ($)	Mar. 31, 2008USD ($)	Dec. 18, 2007USD ($)
Related Party Transaction [Line Items]
Bond, face value						$ 0		$ 10,700,000
Cash collateral								$ 6,600,000
Related party allowance for doubtful accounts receivable				$ 14,000	$ 14,000
Accounts receivable - related parties balance
Right-Of-Use And Easement Bonds [Member]
Related Party Transaction [Line Items]
Bond, face value				1,550,000
Ten Well Program [Member]
Related Party Transaction [Line Items]
Wells in process of drilling | item	10
Number of wildcat wells | item	3
Number of developmental wells | item	7
Cost incurred, development costs for a productive well	$ 400,000
Cost incurred, development costs for a nonproductive well	$ 250,000
Percent of working interest revenue, as a fee		85.00%	25.00%
Payout point multiplier | item	1.35
Related party transaction							$ 3,850,000
Payout point value							$ 5,200,000
Methane Project [Member]
Related Party Transaction [Line Items]
Percent of net profits, interest	75.00%	7.50%	75.00%
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
Suspended portion of accounts payable					634,000
Hoactzin Partners, L.P. [Member] | Methane Project [Member]
Related Party Transaction [Line Items]
Revenue from related party				0
Net profits				0
Related Party [Member]
Related Party Transaction [Line Items]
Related party allowance for doubtful accounts receivable				159,000	159,000
Accounts receivable-related party, allowance for doubtful accounts				159,000	159,000
Related Party [Member] | Hoactzin Partners, L.P. [Member]
Related Party Transaction [Line Items]
Accounts receivable - related parties balance				$ 0	$ 0
At Or Above Revenue Threshold [Member] | Ten Well Program [Member]
Related Party Transaction [Line Items]
Percent of working interest revenue, as a fee	25.00%
Up To Revenue Threshold [Member] | Ten Well Program [Member]
Related Party Transaction [Line Items]
Percent of working interest revenue, as a fee	85.00%

Oil And Gas Properties (Schedul

Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Oil And Gas Properties [Abstract]
Oil and gas properties, at cost	$ 5,042,000		$ 5,042,000		$ 8,286,000
Unevaluated properties	552,000		552,000		552,000
Oil and gas properties	5,594,000		5,594,000		$ 8,838,000
Depletion expense			806,000	$ 1,974,000
Impairment	$ 632,000	$ 7,189,000	$ 2,718,000	$ 7,189,000

Asset Retirement Obligation (As

Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Balance	$ 2,222
Accretion expense	107	$ 94
Liabilities incurred
Liabilities settled	(86)
Balance	$ 2,243

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - Prosperity Bank [Member] - USD ($)	Mar. 28, 2016	Sep. 30, 2016	Mar. 27, 2016
Debt Instrument [Line Items]
Credit facility maturity date		Jan. 30, 2018
Rate above prime		0.50%
Interest rate	4.00%
Credit facility maximum borrowing capacity		$ 40,000,000
Credit facility current borrowing capacity	$ 3,200,000		$ 7,800,000

Long-Term Debt (Schedule Of Lon

Long-Term Debt (Schedule Of Long-Term Debt To Unrelated Entities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Note payable to financial institution, with interest only payment until maturity	$ 2,187	$ 869
Less unamortized debt issuance cost	(15)	(10)
Note payable to a financial institution, net of unamortized debt issuance cost	2,172	859
Installment notes bearing interest at the rate of 4.16% to 4.6% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10	117	152
Total long-term debt	2,289	1,011
Less current maturities	(58)	(65)
Long-term debt, less current maturities	2,231	$ 946
Periodic payments including interest, insurance and maintenance	$ 10
Maximum [Member]
Debt Instrument [Line Items]
Interest rate per annum	4.60%
Minimum [Member]
Debt Instrument [Line Items]
Interest rate per annum	4.16%

Manufactured Methane (Narrative

Manufactured Methane (Narrative) (Details) - Methane Project [Member] - USD ($)	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Methane Project [Line Items]
Date methane facilities were placed into service	Apr. 1, 2009
Methane facilities estimated useful life	33 years
Landfill closure date	Dec. 1, 2041
Depreciation expense	$ 46,000	$ 45,000

Manufactured Methane (Methane F

Manufactured Methane (Methane Facilities) (Details) - Methane Project [Member] - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Manufactured Methane facilities, at cost	$ 1,669	$ 1,633
Accumulated depreciation	(106)	(60)
Manufactured Methane facilities, net	$ 1,563	$ 1,573

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016USD ($)item$ / bbl
Loss Contingencies [Line Items]
Decrease in compensation | $	$ 205,000
Incidence Of Non-Compliance [Member]
Loss Contingencies [Line Items]
Wells issued incidence of non-compliance | item	1
Maximum potential loss | $	$ 386,000
Minimum [Member]
Loss Contingencies [Line Items]
Compensation reduction until WTI posting | $ / bbl	70
Compensation reimbursement at WTI posting | $ / bbl	85