Riley Exploration Permian (REPX) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 25, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
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 Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 10.6
Entity Common Stock, Shares Outstanding		6,084,241

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Assets
Cash and cash equivalents	$ 40,000	$ 35,000
Accounts receivable, less allowance for doubtful accounts of $14	$ 446,000	$ 877,000
Accounts receivable-related party, less allowance for doubtful accounts of $159
Inventory	$ 542,000	$ 804,000
Deferred tax asset-current		68,000
Other current assets	354,000	311,000
Total current assets	1,382,000	2,095,000
Restricted cash		386,000
Loan fees, net	10,000	18,000
Oil and gas properties, net (full cost accounting method)	8,838,000	25,413,000
Manufactured Methane facilities, net	1,573,000	1,634,000
Other property and equipment, net	200,000	200,000
Deferred tax asset - noncurrent		7,283,000
Total assets	12,003,000	37,029,000
Liabilities and Stockholders' Equity
Accounts payable - trade	151,000	455,000
Accounts payable - other	159,000	159,000
Accounts payable - related party	634,000	590,000
Accrued liabilities	356,000	759,000
Current maturities of long-term debt	65,000	65,000
Total current liabilities	1,365,000	2,028,000
Asset retirement obligation	2,222,000	2,008,000
Long term debt, less current maturities	956,000	824,000
Total liabilities	$ 4,543,000	$ 4,860,000
Commitments and contingencies (Note 9)
Stockholders' equity
Common stock, $.001 par value: authorized 100,000,000 Shares; 6,084,241 shares issued and outstanding	$ 6,000	$ 6,000
Additional paid in capital	55,770,000	55,758,000
Accumulated deficit	(48,316,000)	(23,595,000)
Total stockholders' equity	7,460,000	32,169,000
Total liabilities and stockholders' equity	$ 12,003,000	$ 37,029,000

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheets [Abstract]
Accounts receivable, less allowance for doubtful accounts	$ 14	$ 14
Accounts receivable-related party, allowance for doubtful accounts	$ 159	$ 159
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	6,084,241	6,084,241
Common stock, shares outstanding	6,084,241	6,084,241

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statements Of Operations [Abstract]
Revenues	$ 6,164	$ 13,788	$ 15,700
Cost and expenses
Production costs and taxes	4,224	5,994	5,524
Depreciation, depletion, and amortization	2,676	3,030	2,912
General and administrative	2,069	2,707	2,059
Impairment	14,526	2,796
Total cost and expenses	23,495	14,527	10,495
Income (loss) from operations	(17,331)	(739)	5,205
Other income (expense)
Net interest expense	(80)	(88)	(357)
Gain on sale of assets	41	33	118
Total other (expense)	(39)	(55)	(239)
Income (loss) from continuing operations before income tax	(17,370)	(794)	4,966
Deferred income tax expense	(7,351)	12	(1,915)
Current income tax expense		(6)	(95)
Net income (loss) from continuing operations	(24,721)	(788)	2,956
(Loss) from discontinued operations, net of income tax benefit			(137)
Net income (loss)	$ (24,721)	$ (788)	$ 2,819
Net income (loss) per share - Basic
Net income (loss) from continuing operations	$ (4.06)	$ (0.13)	$ 0.49
Net loss from discontinued operations			(0.02)
Net income (loss) per share - Diluted
Net income (loss) from continuing operations	$ (4.06)	$ (0.13)	0.49
Net loss from discontinued operations			$ (0.02)
Shares used in computing earnings per share
Basic	6,084,241	6,084,241	6,084,241
Diluted	6,084,241	6,084,993	6,091,987

Consolidated Statements Of Stoc

Consolidated Statements Of Stockholders' Equity - USD ($) $ in Thousands	Common Stock [Member]	Paid In Capital [Member]	Accumulated Deficit [Member]	Total
Beginning balance, value at Dec. 31, 2012	$ 6	$ 55,754	$ (25,626)	$ 30,134
Beginning balance, shares at Dec. 31, 2012	6,084,241
Net income (loss)			2,819	2,819
Options and compensation expense		(28)		(28)
Ending balance, shares at Dec. 31, 2013	6,084,241
Ending balance, value at Dec. 31, 2013	$ 6	55,726	(22,807)	32,925
Net income (loss)			(788)	(788)
Options and compensation expense		32		32
Ending balance, shares at Dec. 31, 2014	6,084,241
Ending balance, value at Dec. 31, 2014	$ 6	55,758	(23,595)	32,169
Net income (loss)			(24,721)	(24,721)
Options and compensation expense		12		12
Ending balance, shares at Dec. 31, 2015	6,084,241
Ending balance, value at Dec. 31, 2015	$ 6	$ 55,770	$ (48,316)	$ 7,460

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities
Net income (loss) from continuing operations	$ (24,721)	$ (788)	$ 2,956
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, and amortization	2,676	3,030	2,912
Amortization of loan fees-interest expense	10	17	32
Accretion of discount on asset retirement obligation	126	114	120
Impairment	14,526	2,796
Gain on sale of vehicles/equipment	(41)	(33)	(118)
Compensation and services paid in stock options / equipment	12	32	50
Deferred income tax expense	7,351	(12)	1,915
Allowance for doubtful accounts			(84)
Changes in assets and liabilities
Restricted cash	386	121
Accounts receivable	432	576	307
Inventory and other assets	198	450	31
Accounts payable	(58)	58	103
Accrued liabilities	(398)	323	(184)
Settlement on asset retirement obligation	(17)	(113)	(69)
Net cash provided by operating activities - continuing operations	482	6,571	7,971
Net cash (used in) in operating activities - discontinued operations			(85)
Net cash provided by operating activities	482	6,571	7,886
Investing activities
Net additions to oil and gas properties	(570)	(3,708)	(2,314)
Additions to Manufactured Methane facilities		(282)	(2)
Additions to other property & equipment	(1)	(21)	(8)
Proceeds from sale of other property & equipment	30	17	106
Net cash (used in) investing activities - continuing operations	(541)	(3,994)	(2,218)
Net cash provided by investing activities - discontinued operations			1,395
Net cash (used in) investing activities	(541)	(3,994)	(823)
Financing activities
Payment in lieu of exercise of options/warrants			(60)
Proceeds from borrowings	4,300	7,709	7,946
Repayments of borrowings	(4,234)	(10,305)	(13,606)
Loan fees	(2)		(10)
Net cash provided by (used in) financing activities - continuing operations	64	(2,596)	(5,730)
Net cash provided by (used in) financing activities - discontinued operations			(1,310)
Net cash provided by (used in) financing activities	64	(2,596)	(7,040)
Net change in cash and cash equivalents - continuing operations	5	(19)	23
Cash and cash equivalents, beginning of period	35	54	31
Cash and cash equivalents, end of period	40	35	54
Supplemental cash flow information:
Cash interest payments	70	71	325
Cash paid for taxes			38
Supplemental non-cash investing and financing activities:
Financed company vehicles	140	47	188
Asset retirement obligations incurred		46	26
Revisions to asset retirement obligations	$ 112	138	(48)
Capital expenditures included in accounts payable and accrued liabilities		$ 207	$ 175

Description Of Business And Sig

Description Of Business And Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Description Of Business And Significant Accounting Policies [Abstract]
Description Of Business And Significant Accounting Policies	1. Descr iption 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 oil exploration and production is in Kansas. The Company’s primary area of natural gas exploration and production has been the Swan Creek Field in Tennessee. The Company sold all of its oil and gas leases and producing assets in Tennessee on August 16, 2013. The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation, owned and operated a 65 mile intrastate pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. As the Company had entered into an agreement to sell the pipeline asset, it had been classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statement of Operations for the year ended December 31, 2013. The Company sold of all its pipeline related assets on August 16, 2013. (See Note 7. Assets Held for Sale and Discontinued Operations) The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operates treatment and delivery facilities for the extraction of methane gas from nonconventional sources for eventual sale to natural gas and electricity customers. Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The 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 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 consolidated financial statements are appropriate, actual results could differ from those estimates. Revenue Recognition Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized. There were no material natural gas imbalances at December 31, 2015, 2014 or 2013. Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes . No methane gas was sold during 2015 or 2014. Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase. The Company has elected to enter into a sweep account arrangement allowing excess cash balances to be used to temporarily pay down the credit facility, thereby, reducing overall interest cost. Restricted Cash During the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond with RLI Insurance Company to appeal a civil penalty related to issuance of an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) concerning one of the Hoactzin properties operated by the Company pursuant to the Management Agreement (see Note 4). These funds were returned to the Company during the quarter ending December 31, 2015. At December 31, 2014, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash” (see Note 11). 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 per barrel cost which includes production costs and taxes, allocated general and administrative costs, and allocated interest cost. The market component is calculated using the average December oil sales price for 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 year. At December 31, 2015 and 2014, inventory consisted of the following (in thousands): December 31, 2015 2014 Oil – carried at lower of cost or market $ 332 $ 573 Equipment and materials – carried at cost 210 231 Total inventory $ 542 $ 804 Oil and Gas Properties 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 $552,000 and $462,000 in unevaluated properties as of December 31, 2015 and 2014, respectively. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. Asset Retirement Obligation An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Manufactured Methane Facilities The Manufactured Methane facilities were placed into service in April 2009 and are being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041. Other Property and Equipment Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs. Stock-Based Compensation The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We recognize expense on a straight line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company recorded compensation expense of $12,000 in 2015, $32,000 in 2014, and $(28,000) in 2013. Compensation expense in 2013 was impacted by a reversal of $59,500 previously recognized as compensation expense. 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 December 31, 2015 and 2014. At December 31, 2015 and 2014, accounts receivable consisted of the following (in thousands): December 31, 2015 2014 Revenue $ 417 $ 845 Joint interest 21 24 Other 22 22 Allowance for doubtful accounts (14) (14) Total accounts receivable $ 446 $ 877 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. At December 31, 201 5 , federal net operating loss carryforwards amounted to approximately $22.9 million which expire between 2019 and 2032 . The total deferred tax asset was $0 and $7.35 million at December 31, 2015 and 2014, respectively. The $7.35 million reduction related to recording a full allowance of the deferred tax asset primarily due to cumulative losses incurred during the 3 years ended December 31, 2015 . Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized. Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized. Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have never experienced any losses related to these balances. The Company’s primary business activities include oil and electricity sales to a limited number of customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. In addition, the Company sells the electricity generated at the Carter Valley landfill site to a local utility. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s projected results of operations. Revenue from the top three purchasers accounted for 74.5% , 16.1% , and 8.6% of total revenues for year ended December 31, 2015. Revenue from the top three purchasers accounted for 79.3% , 16.5% , and 3.8% of total revenues for year ended December 31, 2014. Revenue from the top three purchasers accounted for 79.8% , 14.9% , and 1.7% of total revenues for year ended December 31, 2013. As of December 31, 2015 and 2014, two of our oil purchasers accounted for 75.7% and 84.5% , respectively of our accounts receivable, of which one oil purchaser accounted for 66.5% and 67.8% , respectively . 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 years ended December 31, 2015 2014 2013 Income (numerator): Net income (loss) from continuing operations $ (24,721) $ (788) $ 2,956 Net loss from discontinued operations — $ — $ (137) Weighted average shares (denominator): Weighted average shares - basic 6,084,241 6,084,241 6,084,241 Dilution effect of share-based compensation, treasury method — 752 7,746 Weighted average shares - dilutive 6,084,241 6,084,993 6,091,987 Earnings (loss) per share – Basic and Dilutive: Continuing Operations $ (4.06) $ (0.13) $ 0.49 Discontinued Operations — $ — $ (0.02) Share and per share information 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. Although the number of shares are subject to change based on true up of actual shares issued as a result of the reverse stock split, the Company expects the change in number of shares will not be material. Fair Value of Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities and long term debt approximates fair value as of December 31, 2015 and 2014. Derivative Financial Instruments The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31, 2015 and 2014, the Company did not have any open derivatives. Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income. Discontinued Operations During 2012, the Company committed to a plan to sell the Swan Creek and Pipeline assets. On March 1, 2013, the Company entered into an agreement to sell the Company’s Swan Creek and Pipeline assets for $1.5 million. Closing of this transaction occurred on August 16, 2013. The related results of operations have been classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statements of Operations for the year ended December 31, 201 3 . The related cash flows have been classified as “Net cash (used in) operating activities – discontinued operations”, “Net cash (used in) investing activities – discontinued operations”, and Net cash (used in) financing activities – discontinued operations”. As the Swan Creek oil and gas assets represented only a small portion of the Company’s full cost pool, these assets remained in oil and gas properties and the gain or loss on the sale was recorded against the full cost pool. Until these properties were sold in August 2013, the related operations were classified in continuing operations. (See Note 7. Assets Held for Sale and Discontinued Operations)

Recent Accounting Pronouncement

Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2015
Recent Accounting Pronouncements [Abstract]
Recent Accounting Pronouncements	2. Recent Accounting Pronouncements In April 2015, the FASB issued ASU 2015-03 Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Cost. This guidance intends to simplify U.S. GAAP by changing the presentation of debt issuance costs. Under the new standard, debt issuance costs will be presented as a reduction of the carrying amount of the related liability, rather than as an asset. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect this to impact its operating results or cash flows. However, for financial statement periods after December 31, 2015, there will be a resulting reclassification of debt issuance costs from assets to a reduction of liabilities. 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 e ffective 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 retrospecitvely to all periods presented. The Company does not expect this to impact its operating results or cash flows.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	3. 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 December 31, 2015, 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 December 31, 2015 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”). 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 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. Dolphin Direct Equity Partners, LP also signed the Payment and Indemnity Agreement, thereby becoming jointly and severally liable with the Company for the obligations to IndemCo. Dolphin Direct Equity Partners, L.P. is a private equity fund controlled by Peter E. Salas that has a significant economic interest in Hoactzin. 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 operator of its own properties, right-of-use and easement (“RUE”) bonds in the amount of $1.55 million were required by the regulatory process to be issued by Argonaut in the Company’s name as current operator. Hoactzin is in the process of transferring these RUE bonds from the Company to Hoactzin. Hoactzin and Dolphin Direct signed an indemnity agreement with Argonaut as well as provided the required collateral for the new Argonaut bonds, including 100% cash collateral for the RUE bonds issued in the Company’s name. The Company is not party to the indemnity agreement with Argonaut and has not provided any collateral for any of the Argonaut bonds issued. When the transfer of the RUE’s and associated bonds is approved, the transfer of operations to Hoactzin would be complete and the Company’s involvement in the Hoactzin properties will be ended. 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 December 31, 2015 and 2014 in the amount of $159,000 . The decrease in payables was due to payment by Hoactzin of invoices received by the Company from IndemCo related to bond premiums, which invoices have been paid by Hoactzin in full and the IndemCo bonds cancelled. The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of December 31, 2015 and 2014 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 December 31, 2015 and 2014. 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 December 31, 2015 and 2014. 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 is suspending drilling payments to Hoactzin. As of December 31, 2015 and 2014, the Company has suspended approximately $634,000 and $590,000 in payments, respectively. 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.

Oil And Gas Properties

Oil And Gas Properties	12 Months Ended
	Dec. 31, 2015
Oil And Gas Properties [Abstract]
Oil And Gas Properties	4. Oil and Gas Properties The following table sets forth information concerning the Company’s oil and gas properties: (in thousands): December 31, 2015 2014 Oil and gas properties, at cost, net of impairment $ 8,286 $ 49,388 Unevaluated properties, at cost 552 462 Accumulated depreciation, depletion and amortization — (24,437) Oil and gas properties, net $ 8,838 $ 25,413 During the years ended December 31, 2015, 2014, and 2013, the Company recorded depletion expense of $2.5 million, $2.8 million and $2.6 million, respectively. In addition, as a result of the ceiling test impairment during 2015, the accumulated depreciation, depletion, and amortization has been netted against the cost to reflect the post impairment value of the oil and gas properties.

Manufactured Methane Facilities

Manufactured Methane Facilities	12 Months Ended
	Dec. 31, 2015
Manufactured Methane Facilities [Abstract]
Manufactured Methane Facilities	5. Manufactured Methane Facilities The following table sets forth information concerning the Manufactured Methane facilities: (in thousands): December 31, 2015 2014 Manufactured Methane facilities, at cost, net of impairment $ 1,634 $ 1,634 Accumulated depreciation (60) — Manufactured Methane facilities, net $ 1,574 $ 1,634 During each of the years ended December 31, 2015, 2014, and 2013, the Company recorded depreciation expense of $60,000 , $163,000 , and $136,000 , respectively. In 2014, the Company recognized a non-cash impairment of the Manufactured Methane facilities in the amount of $2.8 million ( $1.7 million net of tax effect). The impairment resulted from the Company’s assessment that future cash flows, using historical costs and runtimes, were insufficient to recover the Manufactured Methane facilities’ net book value. The Manufactured Methane facilities were written down to fair value amount calculated from estimated discounted cash flows, as well as certain expressions of interest with regards to the purchase by outside parties of the Company’s Manufactured Methane facilities. (See Note 10. Fair Value Measurements)

Other Property And Equipment

Other Property And Equipment	12 Months Ended
	Dec. 31, 2015
Other Property And Equipment [Abstract]
Other Property And Equipment	6. Other Property and Equipment Other property and equipment consisted of the following as of December 31, 2015: (in thousands) Depreciable Accumulated Net Book Type Life Gross Cost Depreciation Value Machinery and equipment 5 -7 yrs $ 20 $ 20 $ — Vehicles 2 -5 yrs 362 162 200 Other 5 yrs 63 63 - Total $ 445 $ 245 $ 200 Other property and equipment consisted of the following as of December 31, 2014: (in thousands) Depreciable Accumulated Net Book Type Life Gross Cost Depreciation Value Machinery and equipment 5 -7 yrs $ 20 $ 17 $ 3 Vehicles 2 -5 yrs 430 233 197 Other 5 yrs 63 63 - Total $ 513 $ 313 $ 200 The Company uses the straight-line method of depreciation for other property and equipment. During each of the years ended December 31, 2015, 2014, and 2013, the Company recorded depreciation expense of $77,000 , $101,000 , and $170,000 , respectively.

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Discontinued Operations	7. Discontinued Operations Discontinued operations represent the income and expenses related to the Company’s pipeline assets. The pipeline assets were sold in August 2013. The following table summarizes the amounts in net loss from discontinued operations, net of income tax presented in the consolidated statement of Operations for the year ended December 31, 2013 (in thousands): Year Ended December 31, 2013 Revenues $ 22 Production costs and taxes (164) Depreciation, depletion, and amortization — Impairment — Gain on sale of assets 128 Deferred income tax benefit (180) Current income tax benefit 57 Net loss from discontinued operations, net of income tax $ (137)

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-Term Debt [Abstract]
Long-Term Debt	8. Long-Term Debt Long-term debt consisted of the following: (in thousands) December 31, 2015 2014 Revolving credit facility, with interest only payment until maturity $ 869 $ 734 Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $8 152 155 Total long-term debt 1,021 889 Less current maturities (65) (65) Long-term debt, less current maturities $ 956 $ 824 Future debt payments to unrelated entities as of December 31, 2015 consisted of the following: (in thousands) 2016 2017 2018 Total Bank Credit Facility $ — $ — $ 869 $ 869 Company Vehicles $ 65 $ 52 $ 35 $ 152 Total $ 65 $ 52 $ 904 $ 1,021 At December 31, 2015, the Company had a revolving credit facility with Prosperity Bank. Under the credit facility, loans and letters of credit are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 million or the Company’s borrowing base in effect from time to time. As of December 31, 2015, the Company’s borrowing base was $7.8 million and the interest rate of prime plus 0.50% per annum. The Company’s borrowing base was reduced to approximately $3.2 million with the March 28, 2016 amendment to the credit agreement. The Company’s interest rate at December 31, 2015 was 4.00% , and matures on January 30, 2018 as amended . The borrowing base remains subject to the existing periodic redetermination provision in the credit facility. The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and the Company’s Manufactured Methane facilities. The credit facility includes certain covenants with which the Company is required to comply. These covenants include leverage, interest coverage, and minimum liquidity ratios. During 2013, 2014, and the first three quarters of 2015, the Company was in compliance with all covenants. However, during the quarter ended December 31, 2015, the Company was not in compliance with the leverage and interest coverage ratios. After the covenant modifications and waivers included in the March 28, 2016 amendment, the Company is now in compliance with all covenants. 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 is now in compliance as a result of the amendment and waivers. The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum. This rate was 4.00% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remained $40 million . The total borrowing by the Company under the Prosperity Bank facility at December 31, 2015 and December 31, 2014 was $869,000 and $734,000 million, respectively. The next borrowing base review will take place in September 2016.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	9. Commitments and Contingencies The Company is a party to lawsuits in the ordinary course of its business. The Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have in the aggregate a material adverse effect on its financial statements. On December 15, 2013, the Company entered into a 38 month lease ( 2 months free) for office space in Greenwood Village Colorado. The payment on this lease is approximately $2,700 per month and expired February 28, 2017. On May 14, 2014, the lease was amended to include additional leased space at the Greenwood Village Colorado office. The amendment extended the lease to expire on May 31, 2017. The monthly lease payments were amended as follows: $3,965.06 per month for the period June 2014 through May 2015; $4,090.94 per month for the period June 2015 through May 2016; $4,216.81 per month for the period June 2016 through May 2017. Future non-cancellable commitments related to this lease total approximately $50,000 due in 2016, and $21,000 due in 2017. Office rent expense for each of the three years ended December 31, 2015, 2014, and 2013 was $49,000 , $73 ,000 , and $92,000 , respectively. The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action calls 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 appeal would have been administratively denied and the order to the Company as operator 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. As a result of the determination by the IBLA, the Company recorded a liability of $386,000 in the Company’s Consolidated Balance Sheets under “Accrued and other current liabilities” and an expense in its Consolidated Statements of Operations under “Production costs and taxes” for the year ended December 31, 2014. On July 14, 2015, the federal district court in the Eastern District of Louisiana 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. During the quarter ended December 31, 2015, the funds held as collateral by RLI Insurance Company were released to the 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 collateralize the appeal bond with RLI Insurance Company and 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 previously. The Company is discussing this analysis, as well as the civil penalty discussed previously, 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. During the quarter ended March 31, 2015, the Company initiated 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 to each employee and members of the Board of Directors if he is still employed by the Company or still a member of the Board of Directors. As of December 31, 2015, the reductions were approximately $142,000 . The Company has not accrued any liabilities associated with these compensation reductions.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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 following table sets forth by level, within the fair value hierarchy, the Company’s assets and liabilities at fair value on a recurring basis as of December 31, 2015 (in thousands): Level 1 Level 2 Level 3 Oil and gas properties $ — $ — $ 8,838 The fair value of the oil and gas properties at December 31, 2015 was based on the quarterly ceiling test calculation performed by the Company. This fair value approximates the future net cash flows of the year end reserves discounted at 10%. 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 December 31, 2015 and December 31, 2014.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	11. 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 years ended December 31, 201 4 and 201 5 (in thousands): Balance December 31, 2013 $ 1,780 Accretion expense 114 Liabilities incurred 46 Liabilities settled (70) Revision in estimated liabilities 138 Balance December 31, 2014 $ 2,008 Accretion expense 126 Liabilities incurred — Liabilities settled (24) Revisions in estimated liabilities 112 Balance December 31, 2015 $ 2,222 The revisions in estimated liabilities in 201 5 and 201 4 resulted primarily from change in timing of wells to be plugged.

Stock Options

Stock Options	12 Months Ended
	Dec. 31, 2015
Stock Options [Abstract]
Stock Options	12. Stock Options In October 2000, the Company approved a Stock Incentive Plan which was effective for a ten -year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the original Plan was not to exceed 7,000,000 . The most recent amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held on June 2, 2008. Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. Furthermore, a participant in the Plan may not, immediately prior to the grant of an Incentive Stock Option, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such a participant is at least 110% of the fair market value of the Company’s stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted. On March 21, 2016, the Company’s shareholders approved a 1 for 10 reverse stock split, effective with trading on March 24, 2016. All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split. The following table summarizes stock option activity in 2015, 2014, and 2013: 2015 2014 2013 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Outstanding, beginning of year 90,025 $ 5.70 87,025 $ 5.90 137,225 $ 6.10 Granted 10,000 $ 2.40 10,000 $ 4.40 7,500 $ 5.40 Exercised — $ — — $ — — $ — Expired/cancelled (54,400) $ 4.80 (7,000) $ 6.30 (57,700) $ 7.20 Outstanding, end of year 45,625 $ 6.10 90,025 $ 5.70 87,025 $ 5.90 Exercisable, end of year 45,625 $ 6.10 90,025 $ 5.70 79,025 $ 6.00 The following table summarizes information about stock options outstanding and exercisable at December 31, 2015: Weighted Average Exercise Price Options Outstanding (shares) Weighted Average Remaining Contractual Life (years) Options Exercisable (shares) $ 10.80 5,000 0.3 5,000 $ 11.60 1,875 0.3 1,875 $ 8.40 1,875 0.5 1,875 $ 7.20 1,875 0.8 1,875 $ 7.50 1,875 1.0 1,875 $ 10.70 1,875 1.3 1,875 $ 8.10 1,875 1.5 1,875 $ 7.30 1,875 1.8 1,875 $ 6.40 1,875 2.0 1,875 $ 6.20 1,875 2.2 1,875 $ 4.80 1,875 2.5 1,875 $ 4.10 1,875 2.8 1,875 $ 4.10 2,500 3.0 2,500 $ 4.80 2,500 3.2 2,500 $ 4.40 2,500 3.5 2,500 $ 4.40 2,500 3.8 2,500 $ 2.50 2,500 4.0 2,500 $ 2.30 2,500 4.2 2,500 $ 2.70 2,500 4.5 2,500 $ 2.20 2,500 4.8 2,500 45,625 45,625 During 2015, the Company issued the following options to each of the non-executive directors that remain outstanding as of December 31, 2015. These options vested upon grant date. Options Issued to Each Non-executive Total Options Issued to Director Non-executive Directors Exercise Price Grant Date Expiration Date 625 2,500 $ 2.50 1/5/2015 1/4/2020 625 2,500 $ 2.30 4/1/2015 3/31/2020 625 2,500 $ 2.70 7/2/2015 7/1/2020 625 2,500 $ 2.20 10/2/2015 10/1/2020 The weighted average fair value per share of options granted in 2015 was $2.40 and 2014 was $2.20 calculated using the Black Scholes option pricing model. Compensation expense related to stock options was $12,000 in 2015 and was $32,000 in 2014 and $(28,000) in 2013. The 2013 amount was comprised of $32,000 of current year compensation expense offset by reversal of $59,500 previously recognized as compensation expense. This expense is recorded in “General and administrative” in the Consolidated Statements of Operations . The fair value of stock options used to compute share based compensation is the estimated present value at grant date using the Black Scholes option pricing model with weighted average assumptions for 2015 of expected volatility of 61.7% , a risk free interest rate of 2.53% and an expected option life remaining from 0.3 to 4.8 years. The weighted average assumptions for 2014 were expected volatility of 53.3% , a risk free interest rate of 3.27% and an expected option life remaining from 0.1 to 4.8 years. The weighted average assumptions used for 2013 were expected volatility of 47.6% , a risk fee interest rate of 2.97% and an expected option life remaining for 0.1 years to 4.8 years. On January 4, 2016, options to purchase 2,500 common shares at $1.20 per share were issued to the Company’s non-executive directors. These options fully vested upon grant date and will expire on January 3, 2021. Shares and price per share information has been adjusted to reflect the impact of this reverse stock split.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Income Taxes	13. Income Taxes The Company had taxable income for the years ended December 31, 201 5, 2014, and 2013. A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2015 Total Statutory rate 34 % Tax (benefit) expense at statutory rate $ (5,906) State income tax (benefit) expense (893) Permanent difference 3 Net change in deferred tax asset valuation allowance 14,147 Total income tax provision (benefit) $ 7,351 Year Ended December 31, 2014 Total Statutory rate 34 % Tax (benefit) expense at statutory rate $ (270) State income tax (benefit) expense (40) Permanent difference 304 Other — Net change in deferred tax asset valuation allowance — Total income tax provision (benefit) $ (6) Year Ended December 31, 2013 Continuing Operations Discontinued Operations Total Statutory rate 34 % 34 % 34 % Tax (benefit) expense at statutory rate $ 1,689 $ (5) $ 1,684 State income tax (benefit) expense 255 — 255 Permanent difference 4 — 4 Other 62 (62) — Net change in deferred tax asset valuation allowance — 190 190 Total income tax provision (benefit) $ 2,010 $ 123 $ 2,133 Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements. The Company believes that all of the positions it has taken will prevail on a more likely than not basis. As such no disclosure of such positions was deemed necessary. Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income. In 2013, management determined using the “more likely than not” criteria for recognition that upon sale of the Pipeline asset, the Company would not be able to utilize the state net operating loss carryforwards associated with TPC and the Tennessee oil and gas properties, and therefore established an allowance for these state net operating loss carryforwards. At December 31, 2015, the Company record ed a full allowance of the deferred tax asset primarily due to cumulated losses incurred during the 3 years ended December 31, 2015 . The total valuation allowance at December 31, 2015 was $15.0 million and $790,000 at December 31, 2014 and 2013. As of December 31, 2015, the Company had net operating loss carry forwards of approximately $22.9 million which will expire between 2018 and 2032 if not utilized. The Company recognizes the excess income tax benefit associated with certain stock compensation deductions when such deductions produce a reduction in the Company’s current tax liability under the “with” and “without” approach. Due to cumulative net operating loss carryforwards (“NOLs”) that exceeded the excess income tax benefits generated in prior reporting periods, the Company has not recognized the excess benefit of the tax deductions upon the exercise of stock options in any prior reporting period. As of December 31, 2015, the Company’s estimated net operating losses for tax return filing purposes exceeds the gross amount for financial reporting purposes by $1.8 million. The tax effect of this excess tax benefit will be recorded as a reduction to APIC in a future reporting period when the cash benefit is realized. Our open tax years include all returns filed for 2011 and later. In addition, any of the Company’s NOLs for tax reporting purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year. The Company’s deferred tax assets and liabilities are as follows: (in thousands) Year Ended December 31, 2015 2014 Net deferred tax assets – current : Bad debt $ 68 $ 68 Valuation allowance (68) Total deferred tax assets – current $ — $ 68 Net deferred tax assets (liabilities) – noncurrent: Net operating loss carryforwards $ 8,963 $ 7,173 Oil and gas properties 4,112 (894) Property, Plant and Equipment 668 711 Asset retirement obligation 870 786 Tax credits 260 202 Miscellaneous 53 95 Valuation allowance (14,926) (790) Total deferred tax assets – noncurrent $ — $ 7,283 Net deferred tax asset $ — $ 7,351

Quarterly Data And Share Inform

Quarterly Data And Share Information	12 Months Ended
	Dec. 31, 2015
Quarterly Data And Share Information [Abstract]
Quarterly Data And Share Information	14. Quarterly Data and Share Information (unaudited) The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per share data) Fiscal Year Ended 2015 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Revenues $ 1,634 $ 1,899 $ 1,425 $ 1,206 Net loss from continuing operations (515) (76) (4,963) (19,167) Loss per common share from continuing operations $ (0.08) $ (0.01) $ (0.82) $ (3.15) Fiscal Year Ended 2014 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Revenues $ 3,505 $ 3,985 $ 3,619 $ 2,679 Net income (loss) from continuing operations 424 377 425 (2,014) Income (loss) per common share from continuing operations $ 0.07 $ 0.06 $ 0.07 $ (0.33)

Supplemental Oil And Gas Inform

Supplemental Oil And Gas Information	12 Months Ended
	Dec. 31, 2015
Supplemental Oil And Gas Information [Abstract]
Supplemental Oil And Gas Information	15. Supplemental Oil and Gas Information (unaudited) Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were located in the United States. Capitalized Costs Related to Oil and Gas Producing Activities The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2015 and 2014 (in thousands): Years Ended December 31, 2015 2014 Proved oil and gas properties $ 8,286 $ 49,388 Unproved properties 552 462 Total proved and unproved oil and gas properties $ 8,838 $ 49,850 Less accumulated depreciation, depletion and amortization — (24,437) Net oil and gas properties $ 8,838 $ 25,413 As a result of the ceiling test impairment during 2015, the accumulated depreciation, depletion, and amortization has been netted against the cost to reflect the post impairment value of the oil and gas properties. Oil and Gas Related Costs The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands): Years Ended December 31, 2015 2014 2013 Property acquisitions proved $ — $ — $ — Property acquisitions unproved 90 598 488 Exploration cost 22 2,367 914 Development cost 252 864 998 Total $ 364 $ 3,829 $ 2,400 Results of Operations from Oil and Gas Producing Activities The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 5,631 $ 13,260 $ 15,325 Production costs and taxes (3,360) (4,876) (4,854) Depreciation, depletion and amortization (2,538) (2,766) (2,606) Impairment (14,526) — — Income (loss) from oil and gas producing activities $ (14,793) $ 5,618 $ 7,865 In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forward position. Estimated Quantities of Oil and Gas Reserves The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2013, 2014 and 2015. All of the Company’s proved reserves are located in the United States of America. Oil (MBbl) Gas (MMcf) MBOE Proved reserves at December 31, 2012 2,213 22 2,217 Revisions of previous estimates (153) 16 (151) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 170 — 170 Production (166) (38) (172) Sales of reserves in place (24) — (24) Proved reserves at December 31, 2013 2,040 — 2,040 Revisions of previous estimates (253) — (253) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 164 — 164 Production (154) — (154) Sales of reserves in place — — — Proved reserves at December 31, 2014 1,797 — 1,797 Revisions of previous estimates (790) — (790) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 1 — 1 Production (131) — (131) Sales of reserves in place — — — Proved reserves at December 31, 2015 877 — 877 Proved developed reserves at: December 31, 2012 1,822 22 1,826 December 31, 2013 1,575 — 1,575 December 31, 2014 1,438 — 1,438 December 31, 2015 877 — 877 Proved undeveloped reserves at: December 31, 2012 391 — 391 December 31, 2013 465 — 465 December 31, 2014 359 — 359 December 31, 2015 — — — The Company’s Proved Undeveloped Reserves at December 31, 2015 included no locations as compared to 27 locations at December 31, 2014. During 2015 , all Proved Undeveloped locations were remove d from the Company’s Proved Reserves primarily due to the low oil prices experienced during 2015. The following table identifies the reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands): Year Ended 12/31/2015 Year Ended 12/31/2014 Year Ended 12/31/2013 Oil Gas Total Oil Gas Total Oil Gas Total Total proved reserves year-end reserve report $ 8,287 — $ 8,287 $ 40,417 — $ 40,417 $ 47,856 — $ 47,856 Proved developed producing reserves (PDP) $ 7,686 — $ 7,686 $ 32,059 — $ 32,059 $ 34,440 — $ 34,440 % of PDP reserves to total proved reserves 93% — 93% 79% — 79% 72% — 72% Proved developed non- producing reserves $ 601 — $ 601 $ 2,956 — $ 2,956 $ 4,868 — $ 4,868 % of PDNP reserves to total proved reserves 7% — 7% 7% — 7% 10% — 10% Proved undeveloped reserves (PUD) $ — — $ — $ 5,402 — $ 5,402 $ 8,548 — $ 8,548 % of PUD reserves to total proved reserves — — — 14% — 14% 18% — 18% S tandardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands): Years Ended December 31, 2015 2014 2013 Future cash inflows $ 38,566 $ 158,792 $ 183,801 Future production costs and taxes (23,500) (71,951) (82,307) Future development costs (951) (10,014) (11,162) Future income tax expenses — (13,092) (18,910) Future net cash flows 14,115 63,735 71,422 Discount at 10% for timing of cash flows (5,828) (29,204) (32,714) Standardized measure of discounted future net cash flows $ 8,287 $ 34,531 $ 38,708 The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands): Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 34,531 $ 38,708 $ 45,354 Sales, net of production costs and taxes (1,901) (8,385) (10,471) Discoveries and extensions, net of costs 5 4,231 4,047 Purchase of reserves in place — — — Sale of reserves in place — — (767) Net changes in prices and production costs (16,009) (829) (1,277) Revisions of quantity estimates (22,431) (6,610) (4,306) Previously estimated development cost incurred during the year — 508 3,149 Changes in future development costs 4,890 (1,913) (1,392) Changes in production rates (timing) and other (56) 1,312 368 Accretion of discount 3,373 4,247 4,593 Net change in income taxes 5,885 3,262 (590) Balance, end of year $ 8,287 $ 34,531 $ 38,708 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average sales prices, along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2015, 2014, and 2013, were $43.98 , $88.34 , $90.11 per barrel of oil respectively. The Company’s proved reserves as of December 31, 2015, 2014 and 2013 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Description Of Business And S22

Description Of Business And Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Description Of Business And Significant Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The 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 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 consolidated financial statements are appropriate, actual results could differ from those estimates.
Revenue Recognition	Revenue Recognition Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized. There were no material natural gas imbalances at December 31, 2015, 2014 or 2013. Methane gas and electricity sales meters are located at the Carter Valley landfill site and sales of electricity are recognized each month based on metered volumes . No methane gas was sold during 2015 or 2014.
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. The Company has elected to enter into a sweep account arrangement allowing excess cash balances to be used to temporarily pay down the credit facility, thereby, reducing overall interest cost.
Restricted Cash	Restricted Cash During the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond with RLI Insurance Company to appeal a civil penalty related to issuance of an “Incident of Non-Compliance” by the Bureau of Safety and Environmental Enforcement (“BSEE”) concerning one of the Hoactzin properties operated by the Company pursuant to the Management Agreement (see Note 4). These funds were returned to the Company during the quarter ending December 31, 2015. At December 31, 2014, this amount was recorded in the Consolidated Balance Sheets under “Restricted cash” (see Note 11).
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 per barrel cost which includes production costs and taxes, allocated general and administrative costs, and allocated interest cost. The market component is calculated using the average December oil sales price for 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 year. At December 31, 2015 and 2014, inventory consisted of the following (in thousands): December 31, 2015 2014 Oil – carried at lower of cost or market $ 332 $ 573 Equipment and materials – carried at cost 210 231 Total inventory $ 542 $ 804
Oil And Gas Properties	Oil and Gas Properties 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 $552,000 and $462,000 in unevaluated properties as of December 31, 2015 and 2014, respectively. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period.
Asset Retirement Obligation	Asset Retirement Obligation An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.
Manufactured Methane Facilities	Manufactured Methane Facilities The Manufactured Methane facilities were placed into service in April 2009 and are being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041.
Other Property And Equipment	Other Property and Equipment Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs.
Stock-Based Compensation	Stock-Based Compensation The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We recognize expense on a straight line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company recorded compensation expense of $12,000 in 2015, $32,000 in 2014, and $(28,000) in 2013. Compensation expense in 2013 was impacted by a reversal of $59,500 previously recognized as compensation expense.
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 December 31, 2015 and 2014. At December 31, 2015 and 2014, accounts receivable consisted of the following (in thousands): December 31, 2015 2014 Revenue $ 417 $ 845 Joint interest 21 24 Other 22 22 Allowance for doubtful accounts (14) (14) Total accounts receivable $ 446 $ 877
Income Taxes	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. At December 31, 201 5 , federal net operating loss carryforwards amounted to approximately $22.9 million which expire between 2019 and 2032 . The total deferred tax asset was $0 and $7.35 million at December 31, 2015 and 2014, respectively. The $7.35 million reduction related to recording a full allowance of the deferred tax asset primarily due to cumulative losses incurred during the 3 years ended December 31, 2015 . Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized. Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.
Concentration Of Credit Risk	Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. We have never experienced any losses related to these balances. The Company’s primary business activities include oil and electricity sales to a limited number of customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. In addition, the Company sells the electricity generated at the Carter Valley landfill site to a local utility. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s projected results of operations. Revenue from the top three purchasers accounted for 74.5% , 16.1% , and 8.6% of total revenues for year ended December 31, 2015. Revenue from the top three purchasers accounted for 79.3% , 16.5% , and 3.8% of total revenues for year ended December 31, 2014. Revenue from the top three purchasers accounted for 79.8% , 14.9% , and 1.7% of total revenues for year ended December 31, 2013. As of December 31, 2015 and 2014, two of our oil purchasers accounted for 75.7% and 84.5% , respectively of our accounts receivable, of which one oil purchaser accounted for 66.5% and 67.8% , respectively .
Earnings Per Common Share	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 years ended December 31, 2015 2014 2013 Income (numerator): Net income (loss) from continuing operations $ (24,721) $ (788) $ 2,956 Net loss from discontinued operations — $ — $ (137) Weighted average shares (denominator): Weighted average shares - basic 6,084,241 6,084,241 6,084,241 Dilution effect of share-based compensation, treasury method — 752 7,746 Weighted average shares - dilutive 6,084,241 6,084,993 6,091,987 Earnings (loss) per share – Basic and Dilutive: Continuing Operations $ (4.06) $ (0.13) $ 0.49 Discontinued Operations — $ — $ (0.02) Share and per share information 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. Although the number of shares are subject to change based on true up of actual shares issued as a result of the reverse stock split, the Company expects the change in number of shares will not be material.
Fair Value Of Financial Instruments	Fair Value of Financial Instruments The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities and long term debt approximates fair value as of December 31, 2015 and 2014.
Derivative Financial Instruments	Derivative Financial Instruments The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31, 2015 and 2014, the Company did not have any open derivatives.
Reclassifications	Reclassifications Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income.
Discontinued Operations	Discontinued Operations During 2012, the Company committed to a plan to sell the Swan Creek and Pipeline assets. On March 1, 2013, the Company entered into an agreement to sell the Company’s Swan Creek and Pipeline assets for $1.5 million. Closing of this transaction occurred on August 16, 2013. The related results of operations have been classified as “(Loss) from discontinued operations, net of income tax benefit” in the Consolidated Statements of Operations for the year ended December 31, 201 3 . The related cash flows have been classified as “Net cash (used in) operating activities – discontinued operations”, “Net cash (used in) investing activities – discontinued operations”, and Net cash (used in) financing activities – discontinued operations”. As the Swan Creek oil and gas assets represented only a small portion of the Company’s full cost pool, these assets remained in oil and gas properties and the gain or loss on the sale was recorded against the full cost pool. Until these properties were sold in August 2013, the related operations were classified in continuing operations. (See Note 7. Assets Held for Sale and Discontinued Operations)

Description Of Business And S23

Description Of Business And Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Description Of Business And Significant Accounting Policies [Abstract]
Schedule Of Inventory	December 31, 2015 2014 Oil – carried at lower of cost or market $ 332 $ 573 Equipment and materials – carried at cost 210 231 Total inventory $ 542 $ 804
Schedule Of Accounts Receivable	December 31, 2015 2014 Revenue $ 417 $ 845 Joint interest 21 24 Other 22 22 Allowance for doubtful accounts (14) (14) Total accounts receivable $ 446 $ 877
Reconciliations Of The Numerators And Denominators Of Our Basic And Diluted Earnings Per Share	For the years ended December 31, 2015 2014 2013 Income (numerator): Net income (loss) from continuing operations $ (24,721) $ (788) $ 2,956 Net loss from discontinued operations — $ — $ (137) Weighted average shares (denominator): Weighted average shares - basic 6,084,241 6,084,241 6,084,241 Dilution effect of share-based compensation, treasury method — 752 7,746 Weighted average shares - dilutive 6,084,241 6,084,993 6,091,987 Earnings (loss) per share – Basic and Dilutive: Continuing Operations $ (4.06) $ (0.13) $ 0.49 Discontinued Operations — $ — $ (0.02)

Oil And Gas Properties (Tables)

Oil And Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Properties [Abstract]
Schedule Of Oil And Gas Properties	December 31, 2015 2014 Oil and gas properties, at cost, net of impairment $ 8,286 $ 49,388 Unevaluated properties, at cost 552 462 Accumulated depreciation, depletion and amortization — (24,437) Oil and gas properties, net $ 8,838 $ 25,413

Manufactured Methane Faciliti25

Manufactured Methane Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Manufactured Methane Facilities [Abstract]
Schedule Of The Manufactured Methane Facilities	December 31, 2015 2014 Manufactured Methane facilities, at cost, net of impairment $ 1,634 $ 1,634 Accumulated depreciation (60) — Manufactured Methane facilities, net $ 1,574 $ 1,634

Other Property And Equipment (T

Other Property And Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Other Property And Equipment [Abstract]
Schedule Of Other Property And Equipment	Other property and equipment consisted of the following as of December 31, 2015: (in thousands) Depreciable Accumulated Net Book Type Life Gross Cost Depreciation Value Machinery and equipment 5 -7 yrs $ 20 $ 20 $ — Vehicles 2 -5 yrs 362 162 200 Other 5 yrs 63 63 - Total $ 445 $ 245 $ 200 Other property and equipment consisted of the following as of December 31, 2014: (in thousands) Depreciable Accumulated Net Book Type Life Gross Cost Depreciation Value Machinery and equipment 5 -7 yrs $ 20 $ 17 $ 3 Vehicles 2 -5 yrs 430 233 197 Other 5 yrs 63 63 - Total $ 513 $ 313 $ 200

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations [Abstract]
Schedule Of The Amounts In Net Loss From Discontinued Operations	Year Ended December 31, 2013 Revenues $ 22 Production costs and taxes (164) Depreciation, depletion, and amortization — Impairment — Gain on sale of assets 128 Deferred income tax benefit (180) Current income tax benefit 57 Net loss from discontinued operations, net of income tax $ (137)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-Term Debt [Abstract]
Schedule of Long-term Debt Instruments	December 31, 2015 2014 Revolving credit facility, with interest only payment until maturity $ 869 $ 734 Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $8 152 155 Total long-term debt 1,021 889 Less current maturities (65) (65) Long-term debt, less current maturities $ 956 $ 824
Schedule Of Future Debt Payments	2016 2017 2018 Total Bank Credit Facility $ — $ — $ 869 $ 869 Company Vehicles $ 65 $ 52 $ 35 $ 152 Total $ 65 $ 52 $ 904 $ 1,021

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Schedule Assets And Liabilities At Fair Value	Level 1 Level 2 Level 3 Oil and gas properties $ — $ — $ 8,838

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation Transactions	Balance December 31, 2013 $ 1,780 Accretion expense 114 Liabilities incurred 46 Liabilities settled (70) Revision in estimated liabilities 138 Balance December 31, 2014 $ 2,008 Accretion expense 126 Liabilities incurred — Liabilities settled (24) Revisions in estimated liabilities 112 Balance December 31, 2015 $ 2,222

Stock Options (Tables)

Stock Options (Tables)	12 Months Ended
	Dec. 31, 2015
Stock Options [Abstract]
Schedule Of Stock Option Activity	2015 2014 2013 Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Outstanding, beginning of year 90,025 $ 5.70 87,025 $ 5.90 137,225 $ 6.10 Granted 10,000 $ 2.40 10,000 $ 4.40 7,500 $ 5.40 Exercised — $ — — $ — — $ — Expired/cancelled (54,400) $ 4.80 (7,000) $ 6.30 (57,700) $ 7.20 Outstanding, end of year 45,625 $ 6.10 90,025 $ 5.70 87,025 $ 5.90 Exercisable, end of year 45,625 $ 6.10 90,025 $ 5.70 79,025 $ 6.00
Schedule Of Stock Options Outstanding And Exercisable	Weighted Average Exercise Price Options Outstanding (shares) Weighted Average Remaining Contractual Life (years) Options Exercisable (shares) $ 10.80 5,000 0.3 5,000 $ 11.60 1,875 0.3 1,875 $ 8.40 1,875 0.5 1,875 $ 7.20 1,875 0.8 1,875 $ 7.50 1,875 1.0 1,875 $ 10.70 1,875 1.3 1,875 $ 8.10 1,875 1.5 1,875 $ 7.30 1,875 1.8 1,875 $ 6.40 1,875 2.0 1,875 $ 6.20 1,875 2.2 1,875 $ 4.80 1,875 2.5 1,875 $ 4.10 1,875 2.8 1,875 $ 4.10 2,500 3.0 2,500 $ 4.80 2,500 3.2 2,500 $ 4.40 2,500 3.5 2,500 $ 4.40 2,500 3.8 2,500 $ 2.50 2,500 4.0 2,500 $ 2.30 2,500 4.2 2,500 $ 2.70 2,500 4.5 2,500 $ 2.20 2,500 4.8 2,500 45,625 45,625
Schedule Of Options Issued	Options Issued to Each Non-executive Total Options Issued to Director Non-executive Directors Exercise Price Grant Date Expiration Date 625 2,500 $ 2.50 1/5/2015 1/4/2020 625 2,500 $ 2.30 4/1/2015 3/31/2020 625 2,500 $ 2.70 7/2/2015 7/1/2020 625 2,500 $ 2.20 10/2/2015 10/1/2020

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision	Year Ended December 31, 2015 Total Statutory rate 34 % Tax (benefit) expense at statutory rate $ (5,906) State income tax (benefit) expense (893) Permanent difference 3 Net change in deferred tax asset valuation allowance 14,147 Total income tax provision (benefit) $ 7,351 Year Ended December 31, 2014 Total Statutory rate 34 % Tax (benefit) expense at statutory rate $ (270) State income tax (benefit) expense (40) Permanent difference 304 Other — Net change in deferred tax asset valuation allowance — Total income tax provision (benefit) $ (6) Year Ended December 31, 2013 Continuing Operations Discontinued Operations Total Statutory rate 34 % 34 % 34 % Tax (benefit) expense at statutory rate $ 1,689 $ (5) $ 1,684 State income tax (benefit) expense 255 — 255 Permanent difference 4 — 4 Other 62 (62) — Net change in deferred tax asset valuation allowance — 190 190 Total income tax provision (benefit) $ 2,010 $ 123 $ 2,133
Schedule Of Deferred Tax Assets And Liabilities	Year Ended December 31, 2015 2014 Net deferred tax assets – current : Bad debt $ 68 $ 68 Valuation allowance (68) Total deferred tax assets – current $ — $ 68 Net deferred tax assets (liabilities) – noncurrent: Net operating loss carryforwards $ 8,963 $ 7,173 Oil and gas properties 4,112 (894) Property, Plant and Equipment 668 711 Asset retirement obligation 870 786 Tax credits 260 202 Miscellaneous 53 95 Valuation allowance (14,926) (790) Total deferred tax assets – noncurrent $ — $ 7,283 Net deferred tax asset $ — $ 7,351

Quarterly Data And Share Info33

Quarterly Data And Share Information (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Data And Share Information [Abstract]
Schedule Of Quarterly Data	Fiscal Year Ended 2015 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Revenues $ 1,634 $ 1,899 $ 1,425 $ 1,206 Net loss from continuing operations (515) (76) (4,963) (19,167) Loss per common share from continuing operations $ (0.08) $ (0.01) $ (0.82) $ (3.15) Fiscal Year Ended 2014 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Revenues $ 3,505 $ 3,985 $ 3,619 $ 2,679 Net income (loss) from continuing operations 424 377 425 (2,014) Income (loss) per common share from continuing operations $ 0.07 $ 0.06 $ 0.07 $ (0.33)

Supplemental Oil And Gas Info34

Supplemental Oil And Gas Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Oil And Gas Information [Abstract]
Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities	Years Ended December 31, 2015 2014 Proved oil and gas properties $ 8,286 $ 49,388 Unproved properties 552 462 Total proved and unproved oil and gas properties $ 8,838 $ 49,850 Less accumulated depreciation, depletion and amortization — (24,437) Net oil and gas properties $ 8,838 $ 25,413
Schedule Of Oil And Gas Property Acquisition, Exploration And Development	Years Ended December 31, 2015 2014 2013 Property acquisitions proved $ — $ — $ — Property acquisitions unproved 90 598 488 Exploration cost 22 2,367 914 Development cost 252 864 998 Total $ 364 $ 3,829 $ 2,400
Schedule Of Results Of Operations From Oil And Gas Producing Activities	Years Ended December 31, 2015 2014 2013 Revenues $ 5,631 $ 13,260 $ 15,325 Production costs and taxes (3,360) (4,876) (4,854) Depreciation, depletion and amortization (2,538) (2,766) (2,606) Impairment (14,526) — — Income (loss) from oil and gas producing activities $ (14,793) $ 5,618 $ 7,865
Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves	Oil (MBbl) Gas (MMcf) MBOE Proved reserves at December 31, 2012 2,213 22 2,217 Revisions of previous estimates (153) 16 (151) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 170 — 170 Production (166) (38) (172) Sales of reserves in place (24) — (24) Proved reserves at December 31, 2013 2,040 — 2,040 Revisions of previous estimates (253) — (253) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 164 — 164 Production (154) — (154) Sales of reserves in place — — — Proved reserves at December 31, 2014 1,797 — 1,797 Revisions of previous estimates (790) — (790) Improved recovery — — — Purchase of reserves in place — — — Extensions and discoveries 1 — 1 Production (131) — (131) Sales of reserves in place — — — Proved reserves at December 31, 2015 877 — 877 Proved developed reserves at: December 31, 2012 1,822 22 1,826 December 31, 2013 1,575 — 1,575 December 31, 2014 1,438 — 1,438 December 31, 2015 877 — 877 Proved undeveloped reserves at: December 31, 2012 391 — 391 December 31, 2013 465 — 465 December 31, 2014 359 — 359 December 31, 2015 — — —
Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves	Year Ended 12/31/2015 Year Ended 12/31/2014 Year Ended 12/31/2013 Oil Gas Total Oil Gas Total Oil Gas Total Total proved reserves year-end reserve report $ 8,287 — $ 8,287 $ 40,417 — $ 40,417 $ 47,856 — $ 47,856 Proved developed producing reserves (PDP) $ 7,686 — $ 7,686 $ 32,059 — $ 32,059 $ 34,440 — $ 34,440 % of PDP reserves to total proved reserves 93% — 93% 79% — 79% 72% — 72% Proved developed non- producing reserves $ 601 — $ 601 $ 2,956 — $ 2,956 $ 4,868 — $ 4,868 % of PDNP reserves to total proved reserves 7% — 7% 7% — 7% 10% — 10% Proved undeveloped reserves (PUD) $ — — $ — $ 5,402 — $ 5,402 $ 8,548 — $ 8,548 % of PUD reserves to total proved reserves — — — 14% — 14% 18% — 18%
Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves	Years Ended December 31, 2015 2014 2013 Future cash inflows $ 38,566 $ 158,792 $ 183,801 Future production costs and taxes (23,500) (71,951) (82,307) Future development costs (951) (10,014) (11,162) Future income tax expenses — (13,092) (18,910) Future net cash flows 14,115 63,735 71,422 Discount at 10% for timing of cash flows (5,828) (29,204) (32,714) Standardized measure of discounted future net cash flows $ 8,287 $ 34,531 $ 38,708
Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves	Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 34,531 $ 38,708 $ 45,354 Sales, net of production costs and taxes (1,901) (8,385) (10,471) Discoveries and extensions, net of costs 5 4,231 4,047 Purchase of reserves in place — — — Sale of reserves in place — — (767) Net changes in prices and production costs (16,009) (829) (1,277) Revisions of quantity estimates (22,431) (6,610) (4,306) Previously estimated development cost incurred during the year — 508 3,149 Changes in future development costs 4,890 (1,913) (1,392) Changes in production rates (timing) and other (56) 1,312 368 Accretion of discount 3,373 4,247 4,593 Net change in income taxes 5,885 3,262 (590) Balance, end of year $ 8,287 $ 34,531 $ 38,708

Description Of Business And S35

Description Of Business And Significant Accounting Policies (Narrative) (Details)	Mar. 21, 2016	Dec. 31, 2015USD ($)mi	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Mar. 01, 2013USD ($)	Dec. 31, 2012USD ($)
Description Of Business And Significant Accounting Policies [Line Items]
Length of pipeline, miles | mi		65
Certificate of Deposit to cover future asset retirement obligations						$ 386,000
Unevaluated properties		$ 552,000	$ 462,000
Current cost discount		10.00%
Allowance for doubtful accounts		$ 14,000	14,000
Compensation expense		12,000	32,000	$ 50,000
Reversal of compensation expense		59,500
Federal net operating loss carryforwards		$ 22,900,000
Deferred tax asset			7,351,000
Deferred tax asset allowance recorded			$ 7,350,000
Sale price of Swan Creek and Pipeline assets					$ 1,500,000
Customer A [Member] | Revenue [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue		74.50%	79.30%	79.80%
Customer B [Member] | Revenue [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue		16.10%	16.50%	14.90%
Customer C [Member] | Revenue [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue		8.60%	3.80%	1.70%
Two Customers [Member] | Accounts Receivable [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue		75.70%	84.50%
Customer D [Member] | Accounts Receivable [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue		66.50%	67.80%
Minimum [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Federal net operating loss carryforwards expiration between, years		Dec. 31, 2019
Maximum [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Federal net operating loss carryforwards expiration between, years		Dec. 31, 2032
Subsequent Event [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Reverse stock split	0.1
Stock Options [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Compensation expense		$ 12,000	$ 32,000	$ (28,000)

Description Of Business And S36

Description Of Business And Significant Accounting Policies (Schedule Of Inventory) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Description Of Business And Significant Accounting Policies [Abstract]
Oil carried at lower of cost or market	$ 332	$ 573
Equipment and materials - carried at cost	210	231
Total inventory	$ 542	$ 804

Description Of Business And S37

Description Of Business And Significant Accounting Policies (Schedule Of Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 446	$ 877
Allowance for doubtful accounts	(14)	(14)
Revenue [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	417	845
Joint Interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	21	24
Other [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 22	$ 22

Description Of Business And S38

Description Of Business And Significant Accounting Policies (Reconciliations Of The Numerators And Denominators Of Our Basic And Diluted Earnings Per Share) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net income (loss) from continuing operations	$ (19,167,000)	$ (4,963,000)	$ (76,000)	$ (515,000)	$ (2,014,000)	$ 425,000	$ 377,000	$ 424,000	$ (24,721,000)	$ (788,000)	$ 2,956,000
Net loss from discontinued operations											$ (137,000)
Weighted average shares - basic									6,084,241	6,084,241	6,084,241
Dilution effect of share-based compensation, treasury method										$ 752	$ 7,746
Weighted average shares - dilutive									6,084,241	6,084,993	6,091,987
Continuing Operations									$ (4.06)	$ (0.13)	$ 0.49
Discontinued Operations											$ (0.02)

Related Party Transactions (Det

Related Party Transactions (Details)	Dec. 18, 2007USD ($)	Sep. 17, 2007USD ($)item	Feb. 28, 2014	Jan. 31, 2014	Mar. 31, 2008USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	May. 15, 2014USD ($)
Productive Wells [Line Items]
Cost incurred, development costs						$ 252,000	$ 864,000	$ 998,000
Working interest percent	15.00%
Bond, face value	$ 10,700,000								$ 0
Cash collateral	$ 6,600,000
Percent of cash collateral						100.00%
Related parties accounts payable						$ 159,000	159,000
Allowance For Doubtful Accounts, Due from Related Parties, Current						159,000	159,000
Accounts payable - related party						634,000	590,000
Right-Of-Use And Easement Bonds [Member]
Productive Wells [Line Items]
Bond, face value						1,550,000
Ten Well Program [Member]
Productive Wells [Line Items]
Wells in process of drilling | item		10
Number of wildcat wells | item		3
Number of developmental wells | item		7
Percent of working interest revenue, as a fee			85.00%	25.00%
Payout point multiplier | item		1.35
Payout point value					$ 5,200,000
Related party transaction					$ 3,850,000
Ten Well Program [Member] | At Or Above Revenue Threshold [Member]
Productive Wells [Line Items]
Percent of working interest revenue, as a fee		85.00%
Ten Well Program [Member] | Up To Revenue Threshold [Member]
Productive Wells [Line Items]
Percent of working interest revenue, as a fee		25.00%
Ten Well Program [Member] | Producing Well [Member]
Productive Wells [Line Items]
Cost incurred, development costs		$ 400,000
Ten Well Program [Member] | Non-Productive Well [Member]
Productive Wells [Line Items]
Cost incurred, development costs		$ 250,000
Methane Project [Member]
Productive Wells [Line Items]
Percent of net profits, interest		75.00%	7.50%	75.00%
Hoactzin [Member]
Productive Wells [Line Items]
Allowance For Doubtful Accounts, Due from Related Parties, Current						$ 159,000	$ 159,000

Oil And Gas Properties (Details

Oil And Gas Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil And Gas Properties [Abstract]
Oil and gas properties, at cost, net of impairment	$ 8,286	$ 49,388
Unevaluated properties, at cost	552	462
Accumulated depreciation, depletion and amortization		(24,437)
Oil and gas properties, net	8,838	25,413
Depletion expense	$ 2,500	$ 2,800	$ 2,600

Manufactured Methane Faciliti41

Manufactured Methane Facilities (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Methane Project [Line Items]
Depreciation expense	$ 77,000	$ 101,000	$ 170,000
Asset Impairment Charges	14,526,000	2,796,000
Methane Project [Member]
Methane Project [Line Items]
Depreciation expense	$ 60,000	163,000	$ 136,000
Asset Impairment Charges		2,800,000
Asset Impairment Charge Net Of Tax		$ 1,700,000

Manufactured Methane Faciliti42

Manufactured Methane Facilities (Schedule Of The Manufactured Methane Facilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Methane Project [Line Items]
Manufactured Methane facilities, at cost, net of impairment	$ 445	$ 513
Accumulated depreciation	(245)	(313)
Manufactured Methane facilities, net	200	200
Methane Project [Member]
Methane Project [Line Items]
Manufactured Methane facilities, at cost, net of impairment	1,634	1,634
Accumulated depreciation	(60)
Manufactured Methane facilities, net	$ 1,574	$ 1,634

Other Property And Equipment (D

Other Property And Equipment (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Gross Cost	$ 445,000	$ 513,000
Accumulated depreciation	245,000	313,000
Manufactured Methane facilities, net	200,000	200,000
Depreciation expense	77,000	101,000	$ 170,000
Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Gross Cost	20,000	20,000
Accumulated depreciation	20,000	17,000
Manufactured Methane facilities, net		3,000
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Gross Cost	362,000	430,000
Accumulated depreciation	162,000	233,000
Manufactured Methane facilities, net	$ 200,000	$ 197,000
Other [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	5 years	5 years
Gross Cost	$ 63,000	$ 63,000
Accumulated depreciation	$ 63,000	$ 63,000
Minimum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	5 years	5 years
Minimum [Member] | Vehicles [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	2 years	2 years
Maximum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	7 years	7 years
Maximum [Member] | Vehicles [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	5 years	5 years

Discontinued Operations (Schedu

Discontinued Operations (Schedule Of The Amounts In Net Loss From Discontinued Operations) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
Discontinued Operations [Abstract]
Revenues	$ 22
Production costs and taxes	(164)
Gain on sale of assets	128
Deferred income tax benefit	(180)
Current income tax benefit	57
Net loss from discontinued operations, net of income tax	$ (137)

Long-Term Debt (Narrative) (Det

Long-Term Debt (Narrative) (Details) - USD ($)	Mar. 28, 2016	Dec. 31, 2015	Mar. 27, 2016	Dec. 31, 2014
Maximum [Member]
Line of Credit Facility [Line Items]
Interest rate per annum		8.25%
Minimum [Member]
Line of Credit Facility [Line Items]
Interest rate per annum		5.50%
F&M Bank [Member]
Line of Credit Facility [Line Items]
Maximum line of credit		$ 40,000,000
Borrowing base		$ 7,800,000
Interest rate per annum		4.00%
Variable interest rate		0.50%
Loans and letters of credit amount outstanding		$ 869,000		$ 734,000,000,000
F&M Bank [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Maximum line of credit	$ 40,000,000
Borrowing base	$ 3,200,000		$ 7,800,000
Interest rate per annum	4.00%
Variable interest rate	0.50%

Long-Term Debt (Schedule Of Lon

Long-Term Debt (Schedule Of Long-term Debt Instruments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Revolving credit facility, with interest only payment until maturity	$ 869	$ 734
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest, insurance and maintenance of approximately $10	152	155
Total long-term debt	1,021	889
Less current maturities	(65)	(65)
Long-term debt, less current maturities	956	$ 824
Interest, insurance and maintenance	$ 8
Maximum [Member]
Line of Credit Facility [Line Items]
Interest rate per annum	8.25%
Minimum [Member]
Line of Credit Facility [Line Items]
Interest rate per annum	5.50%

Long-Term Debt (Schedule Of Fut

Long-Term Debt (Schedule Of Future Debt Payments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Long-Term Debt [Line Items]
2,016	$ 65
2,017	52
2,018	904
Total long-term debt	1,021	$ 889
Bank Credit Facility [Member]
Long-Term Debt [Line Items]
2,018	869
Total long-term debt	869
Company Vehicles [Member]
Long-Term Debt [Line Items]
2,016	65
2,017	52
2,018	35
Total long-term debt	$ 152

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2015$ / bbl	May. 31, 2017USD ($)	May. 31, 2016USD ($)	Dec. 31, 2015USD ($)item	May. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments And Contingencies [Line Items]
Rent expense				$ 49,000		$ 73,000	$ 92,000
Production costs and taxes				4,224,000		5,994,000	$ 5,524,000
Compensation reduction until WTI posting | $ / bbl	70
Compensation reimbursement at WTI posting | $ / bbl	85
Decrease in compensation				$ 142,000
Incidence Of Non-Compliance [Member]
Commitments And Contingencies [Line Items]
Wells issued incidence of non-compliance | item				1
Maximum range of possible payment				$ 386,000
Production costs and taxes						$ 386,000
Denver Colorado [Member]
Commitments And Contingencies [Line Items]
Lease term				38 months
Number of free months in lease				2 months
Leases rent due per month		$ 4,216.81	$ 4,090.94	$ 2,700	$ 3,965.06
Lease due in 2016				50,000
Lease due in 2017				$ 21,000

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Assets And Liabilities At Fair Value) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Oil and gas properties	$ 8,838

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation, Beginning Balance	$ 2,008	$ 1,780
Accretion expense	126	114	$ 120
Liabilities incurred		46
Liabilities settled	(24)	(70)
Revisions in estimated liabilities	112	138	(48)
Asset Retirement Obligation, Ending Balance	$ 2,222	$ 2,008	$ 1,780

Stock Options (Narrative) (Deta

Stock Options (Narrative) (Details)	Mar. 21, 2016	Jan. 04, 2016$ / sharesshares	Feb. 01, 2008shares	Dec. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)	Oct. 25, 2000shares
Stock Options [Line Items]
Number of shares that may be granted | shares							7,000,000
Number of additional shares that may be granted | shares			3,500,000
Stock Incentive Plan term				10 years
Purchase price floor of fair market value				85.00%
Weighted average fair value of options granted | $ / shares				$ 2.40	$ 2.20
Compensation expense				$ 12,000	$ 32,000	$ 50,000
Expected volatility				61.70%	53.30%	47.60%
Risk free interest rate				2.53%	3.27%	2.97%
Stock Options [Member]
Stock Options [Line Items]
Compensation expense				$ 12,000	$ 32,000	$ (28,000)
Current year compensation expense						32,000
Reversal of compensation expense						$ 59,500
Minimum [Member]
Stock Options [Line Items]
Voting power				10.00%
option life remaining				3 months 18 days	1 month 6 days	1 month 6 days
Maximum [Member]
Stock Options [Line Items]
option life remaining				4 years 9 months 18 days	4 years 9 months 18 days	4 years 9 months 18 days
Voluntary Resignation [Member]
Stock Options [Line Items]
Stock Incentive Plan exercisable period				3 months
10% Of Total Voting Power [Member]
Stock Options [Line Items]
Stock Incentive Plan exercisable period				5 years
Purchase price floor of fair market value				110.00%
Subsequent Event [Member]
Stock Options [Line Items]
Options issued to purchase | shares		2,500
Price per share | $ / shares		$ 1.20
Reverse stock split	0.1

Stock Options (Schedule Of Stoc

Stock Options (Schedule Of Stock Option Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Options [Abstract]
Shares, Outstanding beginning of year	90,025	87,025	137,225
Shares, Granted	10,000	10,000	7,500
Shares, Expired/cancelled	(54,400)	(7,000)	(57,700)
Shares, Outstanding end of year	45,625	90,025	87,025
Weighted Average Exercise Price, Outstanding beginning of year	$ 5.70	$ 5.90	$ 6.10
Weighted Average Exercise Price, Granted	2.40	4.40	5.40
Weighted Average Exercise Price, Expired/cancelled	4.80	6.30	7.20
Weighted Average Exercise Price, Outstanding end of year	$ 6.10	$ 5.70	$ 5.90
Excersiable, end of year, Shares	45,625	90,025	79,025
Excersiable, end of year, Weighted Average Exercise Price	$ 6.10	$ 5.70	$ 6

Stock Options (Schedule Of St53

Stock Options (Schedule Of Stock Options Outstanding And Exercisable) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 6.10	$ 5.70	$ 5.90	$ 6.10
Options Outstanding	45,625	90,025	87,025	137,225
Options Exercisable	45,625
$10.08 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 10.80
Options Outstanding	5,000
Weighted Average Remaining Contractual Life	3 months 18 days
Options Exercisable	5,000
$11.60 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 11.60
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	3 months 18 days
Options Exercisable	1,875
$8.40 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 8.40
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	6 months
Options Exercisable	1,875
$7.20 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 7.20
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	9 months 18 days
Options Exercisable	1,875
$7.50 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 7.50
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	1 year
Options Exercisable	1,875
$10.70 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 10.70
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	1 year 3 months 18 days
Options Exercisable	1,875
$8.10 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 8.10
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	1 year 6 months
Options Exercisable	1,875
$7.30 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 7.30
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	1 year 9 months 18 days
Options Exercisable	1,875
$6.40 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 6.40
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	2 years
Options Exercisable	1,875
$6.20 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 6.20
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	2 years 2 months 12 days
Options Exercisable	1,875
$4.80 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.80
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	2 years 6 months
Options Exercisable	1,875
$4.10 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.10
Options Outstanding	1,875
Weighted Average Remaining Contractual Life	2 years 9 months 18 days
Options Exercisable	1,875
$4.10 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.10
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	3 years
Options Exercisable	2,500
$4.80 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.80
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	3 years 2 months 12 days
Options Exercisable	2,500
$4.40 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.40
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	3 years 6 months
Options Exercisable	2,500
$4.40 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 4.40
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	3 years 9 months 18 days
Options Exercisable	2,500
$2.50 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.50
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	4 years
Options Exercisable	2,500
$2.30 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.30
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	4 years 2 months 12 days
Options Exercisable	2,500
$2.70 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.70
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	4 years 6 months
Options Exercisable	2,500
$2.20 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.20
Options Outstanding	2,500
Weighted Average Remaining Contractual Life	4 years 9 months 18 days
Options Exercisable	2,500
$2.50 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.50
$2.30 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 2.30

Stock Options (Schedule Of Opti

Stock Options (Schedule Of Options Issued) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	10,000	10,000	7,500
Exercise Price	$ 6.10	$ 5.70	$ 5.90	$ 6.10
$2.50 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	2.50
$2.30 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	2.30
$2.70 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	2.70
$2.20 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	2.20
$2.50 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$ 2.50
Grant Date	Jan. 5, 2015
Expiration Date	Jan. 4, 2020
$2.50 [Member] | Non-Executive Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	625
$2.50 [Member] | Executive Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	2,500
$2.30 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$ 2.30
Grant Date	Apr. 1, 2015
Expiration Date	Mar. 31, 2020
$2.30 [Member] | Non-Executive Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	625
$2.30 [Member] | Executive Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	2,500
$2.70 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$ 2.70
Grant Date	Jul. 2, 2015
Expiration Date	Jul. 1, 2020
$2.70 [Member] | Non-Executive Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	625
$2.70 [Member] | Executive Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	2,500
$2.20 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise Price	$ 2.20
Grant Date	Oct. 2, 2015
Expiration Date	Oct. 1, 2020
$2.20 [Member] | Non-Executive Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	625
$2.20 [Member] | Executive Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options Issued	2,500

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income tax reconciliation, Permanent differrence	$ (3,000)	$ (304,000)	$ (4,000)
Valuation allowance	14,926,000	$ 790,000	$ 790,000
Federal net operating loss carryforwards	22,900,000
Operating Loss Carryforwards	22,900,000
Estimated Net Operating Losses Exceed Gross Financial Reporting Amount [Member]
Federal net operating loss carryforwards	1,800,000
Operating Loss Carryforwards	$ 1,800,000

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effective Income Tax Rate Reconciliation [Line Items]
Statutory rate	34.00%	34.00%	34.00%
Tax (benefit) expense at statutory rate	$ (5,906)	$ (270)	$ 1,684
State income tax (benefit) expense	(893)	(40)	255
Permanent difference	3	304	4
Net change in deferred tax asset valuation allowance	14,147		190
Total income tax provision (benefit)	$ 7,351	$ (6)	$ 2,133
Continuing Operations [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Statutory rate			34.00%
Tax (benefit) expense at statutory rate			$ 1,689
State income tax (benefit) expense			255
Permanent difference			4
Other			62
Total income tax provision (benefit)			$ 2,010
Discontinued Operations [Member]
Effective Income Tax Rate Reconciliation [Line Items]
Statutory rate			34.00%
Tax (benefit) expense at statutory rate			$ (5)
Other			(62)
Net change in deferred tax asset valuation allowance			190
Total income tax provision (benefit)			$ 123

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Bad debt	$ 68,000	$ 68,000
Valuation allowance	(68,000)
Total deferred tax assets - current		68,000
Net operating loss carryforwards	8,963,000	7,173,000
Oil and gas properties	4,112,000	(894,000)
Property, Plant and Equipment	668,000	711,000
Asset retirement obligation	870,000	786,000
Tax credits	260,000	202,000
Miscellaneous	53,000	95,000
Valuation allowance	$ (14,926,000)	(790,000)	$ (790,000)
Total deferred tax assets - noncurrent		7,283,000
Net deferred tax asset		$ 7,351,000

Quarterly Data And Share Info58

Quarterly Data And Share Information (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Data And Share Information [Abstract]
Revenues	$ 1,206	$ 1,425	$ 1,899	$ 1,634	$ 2,679	$ 3,619	$ 3,985	$ 3,505	$ 6,164	$ 13,788	$ 15,700
Net income (loss) from continuing operations	$ (19,167)	$ (4,963)	$ (76)	$ (515)	$ (2,014)	$ 425	$ 377	$ 424	$ (24,721)	$ (788)	$ 2,956
Income (loss) per common share from continuing operations	$ (3.15)	$ (0.82)	$ (0.01)	$ (0.08)	$ (0.33)	$ 0.07	$ 0.06	$ 0.07	$ (4.06)	$ (0.13)	$ 0.49

Supplemental Oil And Gas Info59

Supplemental Oil And Gas Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl	Dec. 31, 2014item$ / bbl	Dec. 31, 2013$ / bbl
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved undeveloped reserve locations | item		27
Barrel Of Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Price | $ / bbl	43.98	88.34	90.11

Supplemental Oil And Gas Info60

Supplemental Oil And Gas Information (Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Information [Abstract]
Proved oil and gas properties	$ 8,286	$ 49,388
Unproved properties	552	462
Total proved and unproved oil and gas properties	8,838	49,850
Less accumulated depreciation, depletion and amortization		(24,437)
Net oil and gas properties	$ 8,838	$ 25,413

Supplemental Oil And Gas Info61

Supplemental Oil And Gas Information (Schedule Of Oil And Gas Property Acquisition, Exploration And Development) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Information [Abstract]
Property acquisitions unproved	$ 90	$ 598	$ 488
Exploration cost	22	2,367	914
Development cost	252	864	998
Total	$ 364	$ 3,829	$ 2,400

Supplemental Oil And Gas Info62

Supplemental Oil And Gas Information (Schedule Of Results Of Operations From Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Information [Abstract]
Revenues	$ 5,631	$ 13,260	$ 15,325
Production costs and taxes	(3,360)	(4,876)	(4,854)
Depreciation, depletion and amortization	(2,538)	(2,766)	(2,606)
Impairment	(14,526)
Income (loss) from oil and gas producing activities	$ (14,793)	$ 5,618	$ 7,865

Supplemental Oil And Gas Info63

Supplemental Oil And Gas Information (Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves) (Details)	12 Months Ended
	Dec. 31, 2015MBoeMBbls	Dec. 31, 2014MBoeMBbls	Dec. 31, 2013MBoeMMcfMBbls	Dec. 31, 2012MBoeMMcfMBbls
Reserve Quantities [Line Items]
Proved reserves	1,797	2,040	2,217
Revisions of previous estimates	(790)	(253)	(151)
Extensions and discoveries	1	164	170
Production	(131)	(154)	(172)
Sales of reserves in place			(24)
Proved reserves	877	1,797	2,040	2,217
Proved developed reserves (equivalent) | MBoe	877	1,438	1,575	1,826
Proved undeveloped reserves (equivalent) | MBoe		359	465	391
Oil [Member]
Reserve Quantities [Line Items]
Proved reserves	1,797	2,040	2,213
Revisions of previous estimates	(790)	(253)	(153)
Extensions and discoveries	1	164	170
Production	(131)	(154)	(166)
Sales of reserves in place			(24)
Proved reserves	877	1,797	2,040	2,213
Proved developed reserves (volume)	877	1,438	1,575	1,822
Proved undeveloped reserves (volume)		359	465	391
Gas [Member]
Reserve Quantities [Line Items]
Proved reserves | MMcf			22
Revisions of previous estimates | MMcf			16
Production | MMcf			(38)
Proved reserves | MMcf				22
Proved developed reserves (volume) | MMcf				22

Supplemental Oil And Gas Info64

Supplemental Oil And Gas Information (Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reserve Quantities [Line Items]
Total proved reserves year-end reserve report	$ 8,287	$ 40,417	$ 47,856
Proved developed producing reserves (PDP)	$ 7,686	$ 32,059	$ 34,440
% of PDP reserves to total proved reserves	93.00%	79.00%	72.00%
Proved developed non-producing reserves	$ 601	$ 2,956	$ 4,868
% of PDNP reserves to total proved reserves	7.00%	7.00%	10.00%
Proved undeveloped reserves (PUD)		$ 5,402	$ 8,548
% of PUD reserves to total proved reserves		14.00%	18.00%
Oil [Member]
Reserve Quantities [Line Items]
Total proved reserves year-end reserve report	$ 8,287	$ 40,417	$ 47,856
Proved developed producing reserves (PDP)	$ 7,686	$ 32,059	$ 34,440
% of PDP reserves to total proved reserves	93.00%	79.00%	72.00%
Proved developed non-producing reserves	$ 601	$ 2,956	$ 4,868
% of PDNP reserves to total proved reserves	7.00%	7.00%	10.00%
Proved undeveloped reserves (PUD)		$ 5,402	$ 8,548
% of PUD reserves to total proved reserves		14.00%	18.00%

Supplemental Oil And Gas Info65

Supplemental Oil And Gas Information (Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Oil And Gas Information [Abstract]
Future cash inflows	$ 38,566	$ 158,792	$ 183,801
Future production costs and taxes	(23,500)	(71,951)	(82,307)
Future development costs	(951)	(10,014)	(11,162)
Future income tax expenses		(13,092)	(18,910)
Future net cash flows	14,115	63,735	71,422
Discount at 10% for timing of cash flows	(5,828)	(29,204)	(32,714)
Standardized measure of discounted future net cash flows	$ 8,287	$ 34,531	$ 38,708	$ 45,354

Supplemental Oil And Gas Info66

Supplemental Oil And Gas Information (Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil And Gas Information [Abstract]
Balance, beginning of year	$ 34,531	$ 38,708	$ 45,354
Sales, net of production costs and taxes	(1,901)	(8,385)	(10,471)
Discoveries and extensions, net of costs	5	4,231	4,047
Sale of reserves in place			(767)
Net changes in prices and production costs	(16,009)	(829)	(1,277)
Revisions of quantity estimates	(22,431)	(6,610)	(4,306)
Previously estimated development cost incurred during the year		508	3,149
Changes in future development costs	4,890	(1,913)	(1,392)
Changes in production rates (timing) and other	(56)	1,312	368
Accretion of discount	3,373	4,247	4,593
Net change in income taxes	5,885	3,262	(590)
Balance, end of year	$ 8,287	$ 34,531	$ 38,708