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 |