Carbon Energy (CRBO) 10-K 28 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 15, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Natural Gas Co
Entity Central Index Key	86,264
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 32.9
Entity Common Stock, Shares Outstanding		107,655,916

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 305	$ 1,132
Accounts receivable:
Revenue	1,082	2,287
Joint interest billings and other	778	1,038
Commodity derivative asset	408	1,322
Prepaid expense, deposits and other current assets	213	141
Total current assets	2,786	5,920
Oil and gas properties, full cost method of accounting:
Proved, net	25,032	30,698
Unproved	3,194	2,789
Other property and equipment, net	238	304
Total property and equipment, net	28,464	33,791
Investments in affiliates (note 5)	1,025	1,009
Other long-term assets	433	911
Total assets	32,708	41,631
Current liabilities:
Accounts payable and accrued liabilities	5,621	7,792
Firm transportation contract obligations (note 12)	436	487
Total current liabilities	6,057	8,279
Non-current liabilities:
Firm transportation contract obligations (note 12)	416	852
Asset retirement obligations (note 2)	3,095	2,968
Notes payable (note 6)	3,500	2,100
Total non-current liabilities	$ 7,011	$ 5,920
Commitments and contingencies (note 12)
Stockholders' equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2015 and 2014
Common stock, $0.01 par value; authorized 200,000,000 shares, 107,655,916 and 106,875,447 shares issued and outstanding at December 31, 2015 and 2014, respectively	$ 1,077	$ 1,069
Additional paid-in capital	54,394	53,160
Accumulated deficit	(38,130)	(29,832)
Total Carbon stockholders' equity	17,341	24,397
Non-controlling interests	2,299	3,035
Total stockholders' equity	19,640	27,432
Total liabilities and stockholders' equity	$ 32,708	$ 41,631

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Balance Sheets [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued
Preferred stock, shares outstanding
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares issued	107,655,916	106,875,447
Common stock, shares outstanding	107,655,916	106,875,447

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenue:
Oil sales	$ 5,045	$ 12,161
Natural gas sales	5,663	10,344
Commodity derivative gain	852	1,246
Other income	118	325
Total revenue	11,678	24,076
Expenses:
Lease operating expenses	2,910	3,333
Transportation costs	1,710	1,808
Production and property taxes	887	1,656
General and administrative	6,741	6,133
Depreciation, depletion and amortization	2,607	2,954
Accretion of asset retirement obligations	123	$ 117
Impairment of oil and gas properties	5,419
Total expenses	20,397	$ 16,001
Operating (loss) income	(8,719)	8,075
Other income and (expense):
Interest expense	(201)	(471)
Equity investment income	16	$ 8
Other	(30)
Total other expense	(215)	$ (463)
(Loss) income before income taxes	$ (8,934)	7,612
Income tax expense:
Current		377
Net (loss) income	$ (8,934)	7,235
Net loss (income) attributable to non-controlling interests	636	(294)
Net (loss) income attributable to controlling interest	$ (8,298)	$ 6,941
Net (loss) income per common share:
Basic	$ (0.08)	$ 0.06
Diluted	$ (0.08)	$ 0.06
Weighted average common shares outstanding:
Basic	106,700	108,988
Diluted	106,700	114,024

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Non-Controlling Interests	Accumulated Deficit
Beginning balances at Dec. 31, 2013	$ 22,446	$ 1,145	$ 55,029	$ 3,045	$ (36,773)
Beginning balances, (in shares) at Dec. 31, 2013		114,470
Purchase of common stock	(3,261)	$ (82)	(3,179)
Purchase of common stock, Shares		(8,154)
Stock-based compensation	1,492		1,492
Restricted stock activity including vesting and shares exchanged for tax withholding	(176)	$ 6	$ (182)
Restricted stock activity including vesting and shares exchanged for tax withholding, shares		559
Non-controlling interests distributions, net	(304)			$ (304)
Net (loss) income	7,235			294	$ 6,941
Ending balances at Dec. 31, 2014	$ 27,432	$ 1,069	$ 53,160	$ 3,035	$ (29,832)
Ending balances, (in shares) at Dec. 31, 2014		106,875
Stock-based compensation	$ 1,443		$ 1,443
Restricted stock activity including vesting and shares exchanged for tax withholding	(201)	$ 8	$ (209)
Restricted stock activity including vesting and shares exchanged for tax withholding, shares		780
Non-controlling interests distributions, net	(100)			$ (100)
Net (loss) income	(8,934)			(636)	$ (8,298)
Ending balances at Dec. 31, 2015	$ 19,640	$ 1,077	$ 54,394	$ 2,299	$ (38,130)
Ending balances, (in shares) at Dec. 31, 2015		107,655

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net (loss) income	$ (8,934)	$ 7,235
Items not involving cash:
Depreciation, depletion and amortization	2,607	2,954
Accretion of asset retirement obligations	123	$ 117
Impairment of oil and gas properties	5,419
Unrealized derivative loss (gain)	763	$ (1,648)
Stock-based compensation expense	1,443	1,492
Equity investment income	(16)	$ (8)
Other	(12)
Net change in:
Accounts receivable	1,631	$ 37
Prepaid expenses, deposits and other current assets	(72)	(46)
Accounts payable, accrued liabilities and firm transportation contracts	(2,443)	1,563
Net cash provided by operating activities	509	11,696
Cash flows from investing activities:
Development of oil and gas properties and other capital expenditures	$ (3,112)	(9,001)
Acquisition of oil and gas properties		(2,244)
Proceeds from sale of oil and gas properties and other fixed assets	$ 213	15,276
Other long-term assets	464	(408)
Net cash (used in) provided by investing activities	$ (2,435)	3,623
Cash flows from financing activities:
Purchase of common stock		(3,261)
Vested restricted stock exchanged for tax withholding	$ (201)	(176)
Proceeds from notes payable	2,000	5,700
Payments on notes payable	(600)	(16,389)
Distribution to non-controlling interests	(100)	(304)
Net cash provided by (used in) financing activities	1,099	(14,430)
Net (decrease) increase in cash and cash equivalents	(827)	889
Cash and cash equivalents, beginning of period	1,132	243
Cash and cash equivalents, end of period	$ 305	$ 1,132

Organization

Organization	12 Months Ended
	Dec. 31, 2015
Organization [Abstract]
Organization	Note 1 – Organization Carbon Natural Gas Company (“Carbon” or the “Company”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in the United States. The Company’s business is comprised of the assets and properties of Nytis Exploration (USA) Inc. (“Nytis USA”) and its subsidiary Nytis Exploration Company LLC (“Nytis LLC”) which conduct the Company’s operations in the Appalachian and Illinois Basins. Collectively, Carbon, Nytis USA and Nytis LLC are referred to as the Company.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 – Summary of Significant Accounting Policies Accounting policies used by the Company reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such accounting policies are briefly discussed below. Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon and its consolidated subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds interests in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying Consolidated Financial Statements. Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the Consolidated Financial Statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments. Accounts Receivable The Company’s accounts receivables are primarily comprised of oil and natural gas revenues from producing activities conducted primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia and from other exploration and production companies and individuals who own working interests in the properties that the Company operates. The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified. At December 31, 2015 and 2014, the Company had not identified any collection issues related to its oil and gas operations and as a consequence no allowance for doubtful accounts was provided for on those dates. Oil and Natural Gas Sales The Company principally sells its oil and natural gas production to various purchasers in the industry. The table below presents percentages by purchaser that account for 10% or more of our total oil and natural gas sales for the years ended December 31, 2015 and 2014. There are a number of purchasers in the areas where the Company sells its production. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s business. Purchaser 2015 2014 Purchaser A 24 % 29 % Purchaser B 18 % 20 % Purchaser C 15 % 13 % Purchaser D 15 % 11 % The Company recognizes an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2015 and 2014, the Company had a purchaser imbalance receivable of approximately $270,000 and approximately $182,000 which are recognized as a current asset in the Company’s Consolidated Balance Sheets. Accounting for Oil and Gas Operations The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. See Note 3 regarding the Company’s 2015 divestitures. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. The Company performs a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the year ended December 31, 2015, the Company recognized a ceiling test impairment of approximately $5.4 million. For the year ended December 31, 2014, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. Because the ceiling test used previous twelve month period average commodity prices, the effect of declining prices since mid-2014 had a negative impact on the average price used to value our reserves which will lower the ceiling test value in future periods and may result in additional impairments of our oil and gas properties. The effect of price declines will Other Property and Equipment Other property and equipment are recorded at cost upon acquisition. Depreciation of other property and equipment over their estimated useful lives is provided for using the straight-line method over three to seven years. Long-Lived Assets The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired. Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than 5% interest of a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of each investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is accounted for using the equity method of accounting increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques. Asset Retirement Obligations The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs. The following table is a reconciliation of the ARO for the years ended December 31, 2015 and 2014. Year Ended December 31, (in thousands) 2015 2014 Balance at beginning of year $ 2,968 $ 2,699 Accretion expense 123 117 Additions during period 4 152 Balance at end of year $ 3,095 $ 2,968 Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments and its notes payable. The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in Note 10. The carrying amount of the Company’s notes payable approximated fair value since borrowings bear interest at variable rates, which are representative of the Company’s credit adjusted borrowing rate. Commodity Derivative Instruments The Company enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility with an objective to achieve more predictable cash flows. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the Consolidated Balance Sheets and the changes in fair value are recognized as gains or losses in revenues in the Consolidated Statements of Operations. Income Taxes Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized. Stock - Based Compensation Compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). Revenue Recognition Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable. Earnings Per Common Share Basic earnings per common share is computed by dividing the net income attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted (loss) income per share: For the Year Ended (in thousands except per share amounts) 2015 2014 Net (loss) income $ (8,298 ) $ 6,941 Basic weighted-average common shares outstanding during the period 106,700 108,988 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,036 Diluted weighted-average common shares outstanding during the period 106,700 114,024 Basic net (loss) income per common share $ (0.08 ) $ 0.06 Diluted net (loss) income per common share $ (0.08 ) $ 0.06 For the year ended December 31, 2015, the Company had a net loss and therefore the diluted loss per common share calculation exclude the anti-dilutive effects of approximately 163,000 stock options, 250,000 warrants and approximately 5.0 million non-vested shares of restricted stock. In addition, approximately 6.3 million restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. For the year ended December 31, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million warrants that were out-of-the money and approximately 4.7 million restricted performance units subject to future contingencies. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments and asset retirement obligations. Actual results could differ from those estimates and assumptions used. Adopted and Recently Issued Accounting Pronouncements In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early application is not permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the fiscal years ending after December 15, 2016, and annual and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures. In April 2015, the FASB issued new authoritative guidance to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued new authoritative guidance which amended the earlier guidance as it did not address the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under the new guidance, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings. Both of these debt issuance cost related guidances are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle Early adoption is permitted. The Company adopted these guidances and elected to continue presenting the debt issuance costs associated with its Credit Facility as other long-term assets in the Consolidated Balance Sheets. In November 2015, the FASB issued new authoritative guidance to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted.

Dispositions and Acquisitions

Dispositions and Acquisitions	12 Months Ended
	Dec. 31, 2015
Dispositions and Acquisitions [Abstract]
Dispositions and Acquisitions	Note 3 – Dispositions and Acquisitions Liberty Participation Agreement During 2014, Nytis LLC entered into a participation agreement with Liberty Energy LLC (“Liberty”) that allowed Liberty to participate with Nytis LLC in the drilling and completion of wells on certain of Nytis LLC’s leases located in Kentucky. Pursuant to the participation agreement, Liberty paid Nytis LLC approximately $2.8 million for a forty percent (40%) working interest in the covered leases and additional leases acquired post-closing. In accordance with the agreement, Liberty will pay a disproportionate percentage of the costs associated with drilling and completing 20 wells on the covered leases. Following the drilling of these 20 wells, Nytis LLC and Liberty will pay their respective costs on a basis proportionate to their working interests. As of December 31, 2015, Liberty had participated in drilling six horizontal wells pursuant to this agreement. The participation agreement also provided for the reservation by Nytis LLC of an overriding royalty interest with respect to the covered leases, subject to an agreed upon minimum net revenue interest. As the transaction did not significantly alter the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from the participation agreement were recorded as a reduction of the Company’s investment in its proved and unevaluated oil and gas properties. Divestitures During December 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into during October 2014, for the sale of a portion of Nytis LLC’s interest in rights below the base of the Clinton Formation (the “Deep Rights”) underlying certain oil and gas leases located in Kentucky and West Virginia. Pursuant to the PSA, the Sellers reserved (i) a minority working interest in the Deep Rights, (ii) an overriding royalty interest in certain of the Deep Rights and (iii) all rights from the surface to the base of the Clinton formation underlying the leases. In connection with the closing of this transaction, Nytis LLC received approximately $12.4 million in cash. During 2015, the final closing was completed. In connection with the final closing of this transaction, Nytis LLC received an additional $42,000 in cash. In October 2015, the Company received $145,000 for the sale of its interests in seven oil and gas properties located in Bell County, Kentucky. As neither of these transactions significantly altered the relationship between capitalized costs and proved reserves, the Company did not recognize a gain or loss. The proceeds from these divestitures were recorded as a reduction of the Company’s investment in its proved and unproved oil and natural gas properties.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2015
Property and Equipment [Abstract]
Property and Equipment	Note 4 – Property and Equipment Net property and equipment at December 31, 2015 and 2014 consists of the following: (in thousands) As of December 31, 2015 2014 Oil and gas properties: Proved oil and gas properties $ 97,453 $ 95,233 Unproved properties not subject to depletion 3,194 2,789 Accumulated depreciation, depletion, amortization and impairment (72,421 ) (64,535 ) Net oil and gas properties 28,226 33,487 Furniture and fixtures, computer hardware and software, and other equipment 825 1,131 Accumulated depreciation and amortization (587 ) (827 ) Net other property and equipment 238 304 Total net property and equipment $ 28,464 $ 33,791 The Company had approximately $3.2 million and $2.8 million, at December 31, 2015 and 2014, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2015 and 2014, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas: As of December 31, (in thousands) 2015 2014 Illinois Basin: Indiana $ 433 $ 433 Illinois 309 420 Appalachian Basin: Kentucky 1,523 1,142 Ohio 66 66 West Virginia 863 728 Total unproved properties not subject to depletion $ 3,194 $ 2,789 During the years ended December 31, 2015 and 2014, expiring leasehold costs reclassified into proved property were approximately $189,000 and $194,000, respectively. The costs not subject to depletion relate to unproved properties that are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. These costs do not relate to any individually significant projects. The excluded properties are assessed for impairment at least annually. The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $576,000 and $520,000 for the years ended December 31, 2015 and 2014, respectively. Depletion expense related to oil and gas properties for the years ended December 31, 2015 and 2014 was approximately $2.5 million and $2.8 million or $0.93 and $0.95 per Mcfe, respectively. Depreciation and amortization expense related to furniture and fixtures, computer hardware and software and other equipment for the years ended December 31, 2015 and 2014 was approximately $140,000 and $154,000, respectively.

Equity Method Investment

Equity Method Investment	12 Months Ended
	Dec. 31, 2015
Equity Method Investment [Abstract]
Equity Method Investment	Note 5 – Equity Method Investment The Company has a 50% interest in Crawford County Gas Gathering Company, LLC (“CCGGC”) which owns and operates pipelines and related gathering and treating facilities. The Company’s gas production located in Illinois is gathered and transported on CCGGC’s gathering facilities. The Company’s investment in CCGGC is accounted for under the equity method of accounting, and its share of the income or loss is recognized. For the years ended December 31, 2015 and 2014, the Company recorded equity method income of approximately $16,000 and $8,000, respectively, related to this investment.

Bank Credit Facility

Bank Credit Facility	12 Months Ended
	Dec. 31, 2015
Bank Credit Facility [Abstract]
Bank Credit Facility	Note 6 – Bank Credit Facility Nytis LLC’s credit facility with Bank of Oklahoma, which matures in May 2017, has a borrowing base of $20.0 million and a maximum line of credit available under hedging arrangements of $9.5 million. Carbon and Nytis USA are guarantors of Nytis LLC’s obligations under its credit facility. No repayments of principal are required until maturity, except to the extent that outstanding balances exceed the borrowing base then in effect. The Company has the right both to repay principal at any time and to reborrow. Subject to the agreement of the Company and the lender, the size of the credit facility may be increased up to $50.0 million. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. Under certain circumstances the lender may request an interim redetermination. The facility has variable interest rates based upon the ratio of outstanding debt to the borrowing base. Interest rates are based on either an Alternate Base Rate or LIBOR. The portion of the loan based on an “Alternate Base Rate” is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point. The portion based on LIBOR is determined by the rate per annum equal to LIBOR plus between 2.5% and 3.25% for each LIBOR tranche. The credit facility includes a hedging component that provides a line of credit under commodity swap, exchange, collar, cap and fixed price agreements in addition to agreements designated to protect the Company against changes in interest and currency exchange rates. At December 31, 2015, there were approximately $3.5 million in outstanding borrowings and approximately $16.5 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at December 31, 2015 was approximately 2.8%. The credit facility is collateralized by substantially all of the Company’s oil and gas assets. The credit facility includes terms that place limitations on certain types of activities including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, mergers and acquisitions and the payment of dividends. The credit facility requires satisfaction of Nytis LLC’s minimum current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter. Nytis LLC is in compliance with all covenants associated with the credit agreement as of December 31, 2015. As the funded debt ratio is dependent on EBITDAX for the most recently completed fiscal quarter, due to low oil and natural gas prices to date during 2016, the Company may exceed its funded debt ratio for the first quarter of 2016. If this were to occur and the Company was not able to obtain a temporary waiver on the covenant, the Bank of Oklahoma would no longer have an obligation to advance funds or the Credit Facility could be terminated and amounts outstanding could be declared immediately due and payable, subject to notice and cure periods.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Income Taxes	Note 7 – Income Taxes The provision for income taxes for the years ended December 31, 2015 and 2014 consists of the following: (in thousands) Year Ended December 31, 2015 December 31, 2014 Current income tax expense $ - $ 377 Deferred income tax expense (3,733 ) 1,624 Change in valuation allowance 3,773 (1,624 ) Total income tax expense $ - $ 377 The effective income tax rate for the years ended December 31, 2015 and 2014 differed from the statutory U.S. federal income tax rate as follows: Year Ended December 31, 2015 December 31, 2014 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.5 3.4 Percentage depletion in excess of basis 1.3 (7.2 ) Non-controlling interest in consolidated partnerships (.4 ) (1.1 ) True-up of prior year depletion in excess of basis .2 (4.2 ) Stock-based compensation deficiency (1.8 ) - Rate changes of prior year deferreds 4.2 .4 Increase in valuation allowance and other (42.0 ) (21.3 ) Total income tax expense - 5.0 % The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2015 and 2014 are presented below: (in thousands) December 31, 2015 December 31, 2014 Deferred tax assets Net operating loss carryforwards $ 5,433 $ 2,622 Depletion carryforwards 2,570 2,347 Accrual and other 1,318 1,242 Derivatives (213 ) (496 ) Asset retirement obligations 1,168 1,118 Property, plant and equipment 7,185 7,011 Total deferred tax assets 17,461 13,844 Deferred tax liability Interest in partnerships (757 ) (628 ) Less valuation allowance (16,704 ) (13,216 ) Net deferred tax asset $ - $ - The Company has net operating losses (“NOL”) of approximately $12.6 million available to reduce future years’ federal taxable income. The federal net operating losses expire in 2034. The Company has NOL of approximately $25 million available to reduce future years’ state taxable income. These state NOL will expire in the future based upon each jurisdiction’s specific law surrounding NOL carryforwards. Tax returns are subject to audit by various taxation authorities. The results of any audits will be accounted for in the period in which they are determined. The Company believes that the tax positions taken in the Company's tax returns satisfy the more likely than not threshold for benefit recognition. Furthermore, the Company believes it has appropriately addressed material book-tax differences. Carbon is confident that the amounts claimed (or expected to be claimed) in the tax returns reflect the largest amount of such benefits that are greater than fifty percent likely of being realized upon ultimate settlement. Accordingly, no liabilities have been recorded by the Company. Any potential adjustments for uncertain tax positions would be a reclassification between the deferred tax asset related to the Company’s NOL and another deferred tax asset. The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. As of December 31, 2015, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2015
Stockholders' Equity [Abstract]
Stockholders' Equity	Note 8 – Stockholders’ Equity Authorized and Issued Capital Stock As of December 31, 2015, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 107,655,916 were issued and outstanding and 1,000,000 shares of preferred stock with a par value of $0.01 per share, none of which were issued and outstanding. During the year ended December 31, 2015, increases in the Company’s issued and outstanding common stock reflect restricted stock, net of shares exchanged for payroll tax obligations paid by the Company, that vested during the year. Equity Plans Prior to Merger In 2011, pursuant to an Agreement and Plan of Merger by and among St. Lawrence Seaway Corporation (“SLSC”), St. Lawrence Merger Sub, Inc. (“Merger Co.”) and Nytis USA, Merger Co. merged with and into Nytis USA with Nytis USA remaining as the surviving subsidiary of SLSC. Pursuant to the merger, all options, warrants and restricted stock were adjusted to reflect the conversion ratio used in the merger. As of December 31, 2015, the Company has approximately 163,000 options outstanding and exercisable, 250,000 warrants granted by SLSC prior to the merger outstanding and exercisable and approximately 979,000 shares of common stock outstanding that are subject to restricted stock agreements. Nytis USA Stock Option Plan The following table reflects the outstanding option awards as of December 31, 2015 and 2014. The awards were made by Nytis USA prior to the merger and were assumed as a result of the merger. The number of shares and the option exercise price have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger. Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life (Years) Outstanding – January 1, 2014 163,076 $ 0.61 2.0 Outstanding – December 31, 2014 163,076 0.61 1.0 Outstanding – December 31, 2015 163,076 0.61 0.0 Exercisable – December 31, 2015 163,076 $ 0.61 0.0 Nytis USA Warrants As of December 31, 2015, the Company has 250,000 warrants outstanding and exercisable, which were granted by SLSC prior to the merger. These warrants have an exercise price of $1.00 and expire on August 31, 2017. Nytis USA Restricted Stock Plan Under Nytis USA’s restricted stock plan, participants were granted stock without cost to the participant. As of December 31, 2015, there were approximately 979,000 shares of unvested restricted stock granted under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”). The Company accounted for these grants at their intrinsic value. From the dates of grant through March 31, 2013, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through March 31, 2013. In June 2013, the vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017. As such, the Company is recognizing compensation expense for these restricted stock grants based on the fair value of the shares on the date the vesting terms were modified. Compensation costs recognized for these restricted stock grants were approximately $335,000 for the years ended December 31, 2015 and 2014. As of December 31, 2015, Carbon Stock Incentive Plans The Company has two stock plans, the Carbon 2011 and 2015 Stock Incentive Plans (collectively the “Carbon Plans”). The Carbon Plans were approved by the shareholders of the Company and in the aggregate provide for the issuance of 22.6 million shares of common stock to Carbon officers, directors, employees or consultants eligible to receive the awards under the Carbon plans. The Carbon Plans provide for granting Director Stock Awards to non-employee directors and for granting Incentive Stock Options, Non-qualified Stock Options, Restricted Stock Awards, Performance Awards and Phantom Stock Awards, or a combination of the foregoing, as is best suited to the circumstances of the particular employee, officer, director or consultant. Restricted Stock Restricted stock awards for employees vest ratably over a three-year service period or in the case of non-employee directors, the awards vest upon the earlier of a change in control of the Company or the date their membership on the Board of Directors is terminated other than for cause. The Company recognizes compensation expense for these restricted stock grants based on the grant date fair value of the shares, amortized ratably over three years for employee awards (based on the required service period for vesting) and seven years for non-employee director awards (based on a market survey of the average tenure of directors among U.S. public companies). For restricted stock granted in 2015 and 2014, the Company recognized compensation expense based on the grant date fair value of the shares, utilizing an enterprise value approach, using valuation metrics primarily based on multiples of cash flow from operations, production and reserves. For restricted stock and performance units granted in 2013, the Company utilized the closing price of the Company’s stock on the date of grant to recognize compensation expense. The following table shows a summary of the Company’s unvested restricted stock under the Carbon Plans as of December 31, 2015 and 2014 as well as activity during the years then ended. Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, nonvested, January 1, 2014 2,780,003 $ 0.63 Granted 1,600,000 0.59 Vested (856,662 ) 0.63 Restricted stock awards, nonvested, December 31, 2014 3,523,341 0.61 Granted 1,740,000 0.40 Vested (1,283,341 ) 0.62 Restricted stock awards, nonvested, December 31, 2015 3,980,000 $ 0.52 Compensation costs recognized for these restricted stock grants were approximately $762,000 and $811,000 for the years ended December 31, 2015 and 2014, respectively. As of December 31, 2015, there was approximately $1.3 million of unrecognized compensation costs related to these restricted stock grants which the Company expects to be recognized over the next 6.3 years. Restricted Performance Units Performance units represent a contractual right to receive one share of the Company’s common stock subject to the terms and conditions of the agreements including the achievement of the price of the Company’s stock, net asset value per share, net production per share and Adjusted EBITDA (defined as net income (loss) before interest expense, taxes, depreciation, depletion, amortization, accretion of asset retirement obligations, ceiling test write downs of oil and gas properties and the gain or loss on sold properties) per share relative to a defined peer group and the lapse of forfeiture restrictions pursuant to the terms and conditions of the agreements including for certain of the grants, the requirement of continuous employment by the grantee prior to a change in control of the Company. The following table shows a summary of the Company’s unvested performance units as of December 31, 2015 and 2014 as well as activity during the years then ended. Number of Shares Restricted performance units, non-vested, January 1, 2014 3,086,160 Granted 1,600,000 Restricted performance units, non-vested, December 31, 2014 4,686,160 Granted 1,600,000 Restricted performance units, non-vested, December 31, 2015 6,286,160 The Company accounts for the performance units granted during 2012, 2014 and 2015 at their fair value determined at the date of grant, which were $.64, $.59 and $.40 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2015, the Company estimated that none of the performance units granted in 2012, 2014 and 2015 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of December 31, 2015, if change in control and other performance provisions pursuant to the terms and conditions of these agreements are met in full, the estimated unrecognized compensation cost related to the performance units granted in 2012, 2014 and 2015 would be approximately $3.1 million. The performance units granted in 2013 contain specific vesting provisions, no change in control provisions nor any performance conditions other than stock price performance. Due to different earning requirements compared to the performance units granted in 2012, 2014 and 2015, the Company recognizes compensation expense for the performance units granted in 2013 based on the grant date fair value of the performance units, amortized ratably over three years (the performance period). The fair value of the performance units granted in 2013 was estimated using a Monte Carlo simulation (“MCS”) valuation model. MCS is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s common stock and those of the Company’s defined peer group, which was determined to be 92.92%. A risk free interest rate of .39% was determined based on the yield of U.S. Treasury strips with maturities similar to those of the expected term of the performance units which was determined to be 2.87 years. The grant date fair value of these performance units as determined by the valuation model was $.54 per share. Compensation costs recognized for these performance units were approximately $346,000 for the years ended December 31, 2015 and 2014. As of December 31, 2015, there was approximately $127,000 of unrecognized compensation costs related to the performance units granted in 2013. These costs are expected to be recognized over the next four months.

Accounts Payable and Accrued Li

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Accounts Payable and Accrued Liabilities	Note 9 – Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at December 31, 2015 and 2014 consist of the following: (in thousands) As of December 31, 2015 2014 Accounts payable $ 577 $ 742 Oil and gas revenue payable to oil and gas property owners 1,221 1,296 Production taxes payable 59 132 Drilling advances received from joint venture partner 2,115 2,354 Accrued drilling costs 112 166 Accrued lease operating costs 76 74 Accrued ad valorem taxes 496 1,194 Accrued general and administrative expenses 833 1,247 Accrued income taxes payable - 377 Other liabilities 132 210 Total accounts payable and accrued liabilities $ 5,621 $ 7,792

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Fair Value Measurements	Note 10 – Fair Value Measurements Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities; Level 2: Quoted prices in active markets for similar assets or liabilities that are observable for the asset or liability; or Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below for all periods presented. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 by level within the fair value hierarchy: (in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559 December 31, 2014 Assets: Commodity derivatives $ - $ 1,322 $ - $ 1,322 As of December 31, 2015, the Company’s commodity derivative financial instruments are comprised of three natural gas swap agreements and one gas and four oil costless collar agreements. As of December 31, 2014, the Company’s commodity derivative financial instruments were comprised of seven natural gas swap agreements and two oil swap agreements. The fair values of these agreements are determined under an income valuation technique. The valuation model requires a variety of inputs, including contractual terms, published forward prices, volatilities for options and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s credit worthiness, the Company’s credit worthiness and the time value of money. The consideration of these factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparty in all of the Company’s commodity derivative financial instruments is the lender in the Company’s bank credit facility. Assets Measured and Recorded at Fair Value on a Non-recurring Basis The fair value of each of the following assets and liabilities measured and recorded at fair value on a non-recurring basis are based on unobservable pricing inputs and therefore, are included within the Level 3 fair value hierarchy. The Company uses the income valuation technique to estimate the fair value of asset retirement obligations using the amounts and timing of expected future dismantlement costs, credit-adjusted risk-free rates and time value of money. During the years ended December 31, 2015 and 2014, the Company recorded asset retirement obligations for additions of approximately $4,000 and $152,000, respectively. See Note 2 for additional information. To determine the fair value of the proved developed properties acquired in 2014, the Company used a discounted cash flow model based on an income approach and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by first determining the Company’s weighted average cost of capital plus property specific risk premiums for the assets acquired. The proved developed properties acquired have a much longer reserve to production ratio than its peer group and extreme sensitivities to changes in natural gas prices relative to the resultant present value of the proved developed properties. The Company estimated property specific risk premiums taking those factors, among others, into consideration. The fair value of the non-controlling interest in the partnerships the Company is required to consolidate, was determined based on the net discounted cash flows of the proved developed producing properties attributable to the non-controlling interests in these partnerships. The Company assumed certain firm transportation contracts as part of an acquisition in 2011. The fair value of the firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future.

Physical Delivery Contracts and

Physical Delivery Contracts and Commodity Derivatives	12 Months Ended
	Dec. 31, 2015
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Physical Delivery Contracts and Commodity Derivatives	Note 11 – Physical Delivery Contracts and Commodity Derivatives The Company has historically used commodity-based derivative contracts to manage exposures to commodity price on certain of its oil and natural gas production. The Company does not hold or issue derivative financial instruments for speculative or trading purposes. The Company also enters into gas physical delivery contracts to effectively provide gas price hedges. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, these contracts are not recorded at fair value in the Consolidated Financial Statements. As of December 31, 2015, the Company has two short-term physical delivery contracts which require the Company to deliver fixed volumes of natural gas. The Company has sufficient production from its natural gas producing properties delivering to the specific meters under these contracts. The following table summarizes the future production volumes to be delivered and sold under these contracts: Daily Volume Period (Dths per day) Price Contract 1 Jan – Mar 2016 1,300 Index less $0.36 Contract 2 Jan – Sep 2016 611 98% of Index less $0.23 The Company’s other oil and gas sales contracts approximate index prices. The Company’s costless collar and swap agreements as of December 31, 2015 are summarized in the table below: Natural Gas Oil Weighted Weighted Average Average Quarter MMBtu Price (a)(c) Bbl Price (b)(c) Swaps: Jan - Mar 2016 60,000 $ 3.66 - - Apr - Jun 2016 40,000 $ 3.39 - - Jul - Sep 2016 30,000 $ 3.12 - - Oct - Dec 2016 30,000 $ 3.12 - - Jan - Mar 2017 30,000 $ 3.27 - - Apr - Jun 2017 30,000 $ 3.27 - - Jul - Sep 2017 30,000 $ 3.27 - - Oct - Dec 2017 30,000 $ 3.27 - - Collars: Jan – Mar 2016 30,000 $ 2.75-$3.40 6,000 $50.00-$59.00 Apr – Jun 2016 30,000 $ 2.75-$3.40 6,000 $50.00-$59.00 Jul – Sep 2016 30,000 $ 2.75-$3.40 5,500 $48.64-$57.91 Oct – Dec 2016 30,000 $ 2.75-$3.40 4,500 $48.33-$58.00 Jan – Mar 2017 - - 4,500 $48.33-$61.67 Apr – Jun 2017 - - 4,500 $48.33-$61.67 Jul – Sep 2017 - - 4,500 $48.33-$61.67 Oct – Dec 2017 - - 4,500 $48.33-$61.67 (a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month. (c) NYMEX costless collar floor and ceiling prices. For its swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. The following table summarizes the fair value of the derivatives recorded in the Consolidated Balance Sheets. These derivative instruments are not designated as cash flow hedging instruments for accounting purposes: (in thousands) As of December 31, 2015 2014 Commodity derivative contracts: Current assets $ 408 $ 1,322 Non-current assets $ 151 $ - The table below summarizes the commodity settlements and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2015 and 2014. These commodity settlements and unrealized gains and losses are recorded and included in commodity derivative gain in the accompanying Consolidated Statements of Operations. (in thousands) For the year ended December 31, 2015 2014 Commodity derivative contracts: Settlement gains (losses) $ 1,615 $ (402 ) Unrealized (losses) gains (763 ) 1,648 Total settlement and unrealized gains, net $ 852 $ 1,246 Commodity derivative settlement gains and losses are included in cash flows from operating activities in the Company’s Consolidated Statements of Cash Flows. The counterparty in all of the Company’s derivative instruments is the lender in the Company’s bank credit facility. Accordingly, the Company is not required to post collateral since the bank is secured by the Company’s oil and gas assets. The Company nets its derivative instrument fair value amounts executed with its counterparty pursuant to an ISDA master agreement, which provides for the net settlement over the term of the contract and in the event of default or termination of the contract. The following table summarizes the location and fair value amounts of all derivative instruments in the Consolidated Balance Sheet, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheet as of December 31, 2015. Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Current assets $ 429 $ (21 ) $ 408 Other long-term assets 194 (43 ) 151 Total derivative assets $ 623 $ (64 ) $ 559 Commodity derivative liabilities: Current liability $ 21 $ (21 ) $ - Non-current liabilities 43 (43 ) - Total derivative liabilities $ 64 $ (64 ) $ - Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s derivatives are subject to large fluctuations from period to period.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 12 – Commitments and Contingencies The Company has entered into employment agreements with certain executives and officers of the Company. The term of the agreements generally range from one to two years and provide for renewal provisions in one year increments thereafter. The agreements provide for, among other items, severance and continuation of benefit payments upon termination of employment or certain change of control events. The Company has entered into long-term firm transportation contracts to ensure the transport for certain of its gas production to purchasers. Firm transportation volumes and the related demand charges for the remaining term of these contracts at December 31, 2015 are summarized in the table below. Period Dekatherms per day Demand Charges Jan 2016 - Apr 2018 4,450 $ 0.20 - $0.65 May 2018 - May 2020 2,150 $ 0.20 Jun 2020 – May 2036 1,000 $ 0.20 A liability of approximately $852,000 related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheet as of December 31, 2015. The fair value of these firm transportation obligations were determined based upon the contractual obligations assumed by the Company and discounted based upon the Company’s effective borrowing rate. These contractual obligations are being amortized on a monthly basis as the Company pays these firm transportation obligations in the future. In August 2015, a Kentucky court ruled that, absent provisions in a lease, a lessee may not deduct severance taxes prior to calculating royalties on natural gas production. Currently, the case has been remanded back to a district court in Kentucky for trial. The Company is currently evaluating the impact of this ruling and in the interim has established a reserve for potential additional production taxes on certain of its wells in Kentucky. The Company leases, under an operating lease arrangement, approximately 5,500 square feet of administrative office space in Denver, Colorado and approximately 5,300 square feet of office space in Lexington, Kentucky, both of which expire in 2016. For the years ended December 31, 2015 and 2014, the Company incurred rental expenses of $236,000 and $207,000, respectively. The Company has minimum lease payments for its office space and equipment of approximately $176,000 for 2016, $3,000 for 2017 and $2,000 for 2018.

Retirement Savings Plan

Retirement Savings Plan	12 Months Ended
	Dec. 31, 2015
Retirement Savings Plan [Abstract]
Retirement Savings Plan	Note 13 – Retirement Savings Plan The Company has a 401(k) plan available to eligible employees. The plan provides for 6% matching which vests immediately. For the years ended December 31, 2015 and 2014, the Company paid approximately $277,000 and $249,000, respectively, for 401(k) contributions and related administrative expenses.

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosure	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Disclosure [Abstract]
Supplemental Cash Flow Disclosure	Note 14 – Supplemental Cash Flow Disclosure Supplemental cash flow disclosures for the years ended December 31, 2015 and 2014 are presented below: (in thousands) For the Year Ended December 31, 2015 2014 Cash paid during the period for: Interest payments $ 166 $ 482 Income taxes 325 - Non-cash transactions: Increase in net asset retirement obligations $ 4 $ 152 Decrease in accounts payable and accrued liabilities included in oil and gas properties $ (215 ) $ (930 )

Supplemental Financial Data - O

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2015
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) [Abstract]
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	Note 15– Supplemental Financial Data – Oil and Gas Producing Activities (unaudited) Estimated Proved Oil and Gas Reserves The reserve estimates as of December 31, 2015 and 2014 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance. Proved oil and gas reserves as of December 31, 2015 and 2014 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. SEC rules dictate the types of technologies that a company may use to establish reserve estimates, including the extraction of non-traditional resources, such as bitumen extracted from oil sands as well as oil and gas extracted from shales. The Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in its net proved oil and gas reserves for 2015 and 2014 are presented in the table below. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and gas during the twelve month period prior to the reporting date of December 31, 2015 and 2014 unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. The independent petroleum engineering firm, Cawley, Gillespie & Associates, Inc. (“CGA”), evaluated and prepared independent estimated proved reserves quantities and related pre-tax future cash flows as of December 31, 2015 and 2014. To facilitate the preparation of an independent reserve study, we provided CGA our reserve database and related supporting technical, economic, production and ownership information. Estimated reserves and related pre-tax future cash flows for the non-controlling interests of the consolidated partnerships included in the Company’s Consolidated Financial Statements, were based on CGA’s estimated reserves and related pre-tax future cash flows for the specific properties in the partnerships and have been added to CGA’s reserve estimates for December 31, 2015 and 2014. See Note 2 for additional information. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2015 and 2014 are as follows: 2015 2014 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 853 36,948 42,066 822 36,684 41,616 Revisions of previous estimates (185 ) (4,670 ) (5,780 ) (40 ) 2,358 2,118 Extensions and discoveries 31 - 186 205 44 1,274 Production (101 ) (2,040 ) (2,646 ) (134 ) (2,138 ) (2,942 ) Purchases of reserves in-place - 138 138 - - - Sales of reserves in-place - (418 ) (418 ) - - - Proved reserves, end of year 598 29,958 33,546 853 36,948 42,066 Proved developed reserves at: End of Year 554 29,958 33,282 770 35,935 40,555 Proved undeveloped reserves at: End of Year 44 - 264 83 1,013 1,511 The estimated proved reserves for December 31, 2015 and 2014 includes 3.0 and 3.3 Bcfe, respectively, attributed to non-controlling interests of consolidated partnerships. Aggregate Capitalized Costs The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows: 2015 2014 (in thousands) Oil and gas properties Proved oil and gas properties $ 97,453 $ 95,233 Unproved properties not subject to depletion 3,194 2,789 Accumulated depreciation, depletion, amortization and impairment (72,421 ) (64,535 ) Net oil and gas properties $ 28,226 $ 33,487 Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2015 and 2014: 2015 2014 (in thousands) Property acquisition costs: Unevaluated properties $ 341 $ 2,165 Proved properties and gathering facilities - 78 Development costs 2,106 8,685 Gathering facilities 578 144 Asset retirement obligation 4 152 Total costs incurred $ 3,029 $ 11,224 The Company’s investment in unproved properties as of December 31, 2015, by the year in which such costs were incurred is set forth in the table below: 2015 2014 2013 and Prior (in thousands) Acquisition costs $ 341 $ 1,762 $ 1,091 Results of Operations from Oil and Gas Producing Activities Results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014 are presented below: 2015 2014 (in thousands) Oil and gas sales, including commodity derivative gains $ 11,560 $ 23,789 Expenses: Production expenses 5,507 6,797 Depletion expense 2,466 2,800 Accretion of asset retirement obligations 123 117 Impairment of oil and gas properties 5,419 - Total expenses 13,515 9,714 Results of operations from oil and gas producing activities $ (1,955 ) $ 14,075 Depletion rate per Mcfe $ 0.93 $ 0.95 Standardized Measure of Discounted Future Net Cash Flows Future oil and gas sales are calculated applying the prices used in estimating the Company’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves. All cash flow amounts, including income taxes, are discounted at 10%. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not rely upon the information that follows in making investment decisions. December 31, 2015 2014 (in thousands) Future cash inflows $ 102,741 $ 250,659 Future production costs (47,117 ) (96,035 ) Future development costs (420 ) (3,908 ) Future income taxes - (32,234 ) Future net cash flows 55,204 118,482 10% annual discount (30,172 ) (53,476 ) Standardized measure of discounted future net cash flows $ 25,032 $ 65,006 Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows: December 31, 2015 2014 (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 65,006 $ 56,442 Sales of oil and gas, net of production costs and taxes (5,283 ) (15,746 ) Price revisions (37,490 ) 10,220 Extensions, discoveries and improved recovery, less related costs 384 6,561 Changes in estimated future development costs 3,290 959 Development costs incurred during the period - 1,010 Quantity revisions (4,282 ) 3,490 Accretion of discount 6,702 5,644 Net changes in future income taxes 2,010 (2,010 ) Purchases of reserves-in-place 115 - Sales of reserves-in-place (380 ) - Changes in production rate timing and other (5,040 ) (1,564 ) Standardized measure of discounted future net cash flows, end of year $ 25,032 $ 65,006 The twelve month weighted averaged adjusted prices in effect at December 31, 2015 and 2014 were as follows: 2015 2014 Oil (per Bbl) $ 46.12 $ 92.10 Natural Gas (per Mcf) $ 2.50 $ 4.64

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Consolidated Financial Statements include the accounts of Carbon and its consolidated subsidiaries. The Company owns 100% of Nytis USA. Nytis USA owns approximately 99% of Nytis LLC. Nytis LLC also holds interests in various oil and gas partnerships. For partnerships where the Company has a controlling interest, the partnerships are consolidated. The Company is currently consolidating on a pro-rata basis 46 partnerships. In these instances, the Company reflects the non-controlling ownership interest in partnerships and subsidiaries as non-controlling interests on its Consolidated Statements of Operations and also reflects the non-controlling ownership interest in the net assets of the partnerships as non-controlling interests within stockholders’ equity on its Consolidated Balance Sheets. All significant intercompany accounts and transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s Consolidated Financial Statements also include its pro-rata share of assets, liabilities, income, lease operating costs and general and administrative expenses of the oil and gas partnerships in which the Company has a non-controlling interest. Non-majority owned investments that do not meet the criteria for pro-rata consolidation are accounted for using the equity method when the Company has the ability to significantly influence the operating decisions of the investee. When the Company does not have the ability to significantly influence the operating decisions of an investee, the cost method is used. All transactions, if any, with investees have been eliminated in the accompanying Consolidated Financial Statements.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents, if any, in excess of daily requirements have been generally invested in money market accounts, certificates of deposits and other cash equivalents with maturities of three months or less. Such investments are deemed to be cash equivalents for purposes of the Consolidated Financial Statements. The carrying amount of cash equivalents approximates fair value because of the short maturity and high credit quality of these investments.
Accounts Receivable	Accounts Receivable The Company’s accounts receivables are primarily comprised of oil and natural gas revenues from producing activities conducted primarily in Illinois, Indiana, Kentucky, Ohio, Tennessee and West Virginia and from other exploration and production companies and individuals who own working interests in the properties that the Company operates. The Company grants credit to all qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon its historical experience and any specific customer collection issues that it has identified. At December 31, 2015 and 2014, the Company had not identified any collection issues related to its oil and gas operations and as a consequence no allowance for doubtful accounts was provided for on those dates.
Oil and Natural Gas Sales	Oil and Natural Gas Sales The Company principally sells its oil and natural gas production to various purchasers in the industry. The table below presents percentages by purchaser that account for 10% or more of our total oil and natural gas sales for the years ended December 31, 2015 and 2014. There are a number of purchasers in the areas where the Company sells its production. Management does not believe that changing its primary purchasers or a loss of any other single purchaser would materially impact the Company’s business. Purchaser 2015 2014 Purchaser A 24 % 29 % Purchaser B 18 % 20 % Purchaser C 15 % 13 % Purchaser D 15 % 11 % The Company recognizes an asset or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers. A purchaser imbalance asset occurs when the Company delivers more natural gas than it nominated to deliver to the purchaser and the purchaser pays only for the nominated amount. Conversely, a purchaser imbalance liability occurs when the Company delivers less natural gas than it nominated to deliver to the purchaser and the purchaser pays for the amount nominated. As of December 31, 2015 and 2014, the Company had a purchaser imbalance receivable of approximately $270,000 and approximately $182,000 which are recognized as a current asset in the Company’s Consolidated Balance Sheets.
Accounting for Oil and Gas Operations	Accounting for Oil and Gas Operations The Company uses the full cost method of accounting for oil and gas properties. Accordingly, all costs related to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Overhead costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment at least annually. Significant unproved properties are assessed individually. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using capitalized costs, including estimated asset retirement costs, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. See Note 3 regarding the Company’s 2015 divestitures. All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. The Company performs a ceiling test quarterly. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement, rather it is a standardized mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs. Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods. For the year ended December 31, 2015, the Company recognized a ceiling test impairment of approximately $5.4 million. For the year ended December 31, 2014, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation. Future declines in oil and natural gas prices could result in impairments of our oil and gas properties in future periods. Because the ceiling test used previous twelve month period average commodity prices, the effect of declining prices since mid-2014 had a negative impact on the average price used to value our reserves which will lower the ceiling test value in future periods and may result in additional impairments of our oil and gas properties. The effect of price declines will impact the ceiling test value until such time commodity prices stabilize or improve. Impairment changes are a non-cash charge and accordingly would not affect cash flows but would adversely affect our net income and shareholders’ equity.
Other Property and Equipment	Other Property and Equipment Other property and equipment are recorded at cost upon acquisition. Depreciation of other property and equipment over their estimated useful lives is provided for using the straight-line method over three to seven years.
Long-Lived Assets	Long-Lived Assets The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company looks primarily to the estimated undiscounted future cash flows in its assessment of whether or not long-lived assets have been impaired.
Investments in Affiliates	Investments in Affiliates Investments in non-consolidated affiliates are accounted for under either the equity or cost method of accounting as appropriate. The cost method of accounting is used for investments in affiliates in which the Company has less than 20% of the voting interests of a corporate affiliate or less than 5% interest of a partnership or limited liability company and does not have significant influence. Investments in non-consolidated affiliates, accounted for using the cost method of accounting, are recorded at cost and an impairment assessment of each investment is made annually to determine if a decline in the fair value of the investment, other than temporary, has occurred. A permanent impairment is recognized if a decline in the fair value occurs. If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment. The Company’s investment in an affiliate that is accounted for using the equity method of accounting increases or decreases by the Company’s share of the affiliate’s profits or losses and such profits or losses are recognized in the Company’s Consolidated Statements of Operations. The Company reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques.
Asset Retirement Obligations	Asset Retirement Obligations The Company’s asset retirement obligations (“ARO”) relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an ARO is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted on a units-of-production basis as part of the full cost pool. Revisions to estimated AROs result in adjustments to the related capitalized asset and corresponding liability. The estimated ARO liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or increased as a result of a reassessment of expected cash flows and assumptions inherent in the estimation of the liability. Upward revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. AROs are valued utilizing Level 3 fair value measurement inputs. The following table is a reconciliation of the ARO for the years ended December 31, 2015 and 2014. Year Ended December 31, (in thousands) 2015 2014 Balance at beginning of year $ 2,968 $ 2,699 Accretion expense 123 117 Additions during period 4 152 Balance at end of year $ 3,095 $ 2,968
Financial Instruments	Financial Instruments The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, commodity derivative instruments and its notes payable. The carrying value of cash and cash equivalents, accounts receivables, payables and accrued liabilities are considered to be representative of their fair value, due to the short maturity of these instruments. The Company’s commodity derivative instruments are recorded at fair value, as discussed below and in Note 10. The carrying amount of the Company’s notes payable approximated fair value since borrowings bear interest at variable rates, which are representative of the Company’s credit adjusted borrowing rate.
Commodity Derivative Instruments	Commodity Derivative Instruments The Company enters into commodity derivative contracts to manage its exposure to oil and natural gas price volatility with an objective to achieve more predictable cash flows. Commodity derivative contracts may take the form of futures contracts, swaps, collars or options. The Company has elected not to designate its derivatives as cash flow hedges. All derivatives are initially and subsequently measured at estimated fair value and recorded as assets or liabilities on the Consolidated Balance Sheets and the changes in fair value are recognized as gains or losses in revenues in the Consolidated Statements of Operations.
Income Taxes	Income Taxes Carbon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating losses and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more likely than not recognition threshold are recognized.
Stock - Based Compensation	Stock - Based Compensation Compensation cost is measured at the grant date, based on the fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period).
Revenue Recognition	Revenue Recognition Oil and natural gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. Natural gas revenues are recognized on the basis of the Company’s net working revenue interest. Net deliveries in excess of entitled amounts are recorded as a liability, while net deliveries lower than entitled amounts are recorded as a receivable.
Earnings Per Common Share	Earnings Per Common Share Basic earnings per common share is computed by dividing the net income attributable to common stockholders for the period by the weighted average number of common shares outstanding during the period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation of basic net income per share only after the shares become fully vested. Diluted earnings per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of options and warrants to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period). The following table sets forth the calculation of basic and diluted (loss) income per share: For the Year Ended (in thousands except per share amounts) 2015 2014 Net (loss) income $ (8,298 ) $ 6,941 Basic weighted-average common shares outstanding during the period 106,700 108,988 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,036 Diluted weighted-average common shares outstanding during the period 106,700 114,024 Basic net (loss) income per common share $ (0.08 ) $ 0.06 Diluted net (loss) income per common share $ (0.08 ) $ 0.06 For the year ended December 31, 2015, the Company had a net loss and therefore the diluted loss per common share calculation exclude the anti-dilutive effects of approximately 163,000 stock options, 250,000 warrants and approximately 5.0 million non-vested shares of restricted stock. In addition, approximately 6.3 million restricted performance units subject to future contingencies were excluded from the basic and diluted loss per share calculations. For the year ended December 31, 2014, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million warrants that were out-of-the money and approximately 4.7 million restricted performance units subject to future contingencies.
Use of Estimates in the Preparation of Financial Statements	Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and expenses and disclosure of contingent assets and liabilities. Significant items subject to such estimates and assumptions include the carrying value of oil and gas properties, the estimate of proved oil and gas reserve volumes and the related depletion and present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, determining the amounts recorded for deferred income taxes, stock-based compensation, fair value of commodity derivative instruments and asset retirement obligations. Actual results could differ from those estimates and assumptions used.
Adopted and Recently Issued Accounting Pronouncements	Adopted and Recently Issued Accounting Pronouncements In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue from contracts with customers. This guidance is to be applied using a retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early application is not permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures. In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the fiscal years ending after December 15, 2016, and annual and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures. In April 2015, the FASB issued new authoritative guidance to simplify the presentation of debt issuance costs in financial statements by presenting such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. In August 2015, the FASB issued new authoritative guidance which amended the earlier guidance as it did not address the balance sheet presentation of debt issuance costs incurred in connection with line-of-credit arrangements. Under the new guidance, a company may defer debt issuance costs associated with line-of-credit arrangements and present such costs as an asset, subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings. Both of these debt issuance cost related guidances are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, should be applied retrospectively and represent a change in accounting principle Early adoption is permitted. The Company adopted these guidances and elected to continue presenting the debt issuance costs associated with its Credit Facility as other long-term assets in the Consolidated Balance Sheets. In November 2015, the FASB issued new authoritative guidance to simplify the financial statement presentation of deferred taxes by presenting both current and noncurrent deferred tax assets and liabilities as noncurrent on the balance sheet. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016 and may be applied either prospectively or retrospectively to all periods presented, and early adoption is permitted.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies [Abstract]
Summary of percentages by purchaser that account for 10% or more of total oil and natural gas sales	Purchaser 2015 2014 Purchaser A 24 % 29 % Purchaser B 18 % 20 % Purchaser C 15 % 13 % Purchaser D 15 % 11 %
Summary of reconciliation of the ARO	Year Ended December 31, (in thousands) 2015 2014 Balance at beginning of year $ 2,968 $ 2,699 Accretion expense 123 117 Additions during period 4 152 Balance at end of year $ 3,095 $ 2,968
Schedule of basic and diluted (loss) income per share	For the Year Ended (in thousands except per share amounts) 2015 2014 Net (loss) income $ (8,298 ) $ 6,941 Basic weighted-average common shares outstanding during the period 106,700 108,988 Add dilutive effects of stock options, warrants and non-vested shares of restricted stock - 5,036 Diluted weighted-average common shares outstanding during the period 106,700 114,024 Basic net (loss) income per common share $ (0.08 ) $ 0.06 Diluted net (loss) income per common share $ (0.08 ) $ 0.06

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property and Equipment [Abstract]
Summary of net property and equipment	(in thousands) As of December 31, 2015 2014 Oil and gas properties: Proved oil and gas properties $ 97,453 $ 95,233 Unproved properties not subject to depletion 3,194 2,789 Accumulated depreciation, depletion, amortization and impairment (72,421 ) (64,535 ) Net oil and gas properties 28,226 33,487 Furniture and fixtures, computer hardware and software, and other equipment 825 1,131 Accumulated depreciation and amortization (587 ) (827 ) Net other property and equipment 238 304 Total net property and equipment $ 28,464 $ 33,791
Summary of unproved oil and gas properties	As of December 31, (in thousands) 2015 2014 Illinois Basin: Indiana $ 433 $ 433 Illinois 309 420 Appalachian Basin: Kentucky 1,523 1,142 Ohio 66 66 West Virginia 863 728 Total unproved properties not subject to depletion $ 3,194 $ 2,789

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Summary of provision for income taxes	(in thousands) Year Ended December 31, 2015 December 31, 2014 Current income tax expense $ - $ 377 Deferred income tax expense (3,733 ) 1,624 Change in valuation allowance 3,773 (1,624 ) Total income tax expense $ - $ 377
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate	Year Ended December 31, 2015 December 31, 2014 Federal income tax rate 35.0 % 35.0 % State income taxes, net of federal benefit 3.5 3.4 Percentage depletion in excess of basis 1.3 (7.2 ) Non-controlling interest in consolidated partnerships (.4 ) (1.1 ) True-up of prior year depletion in excess of basis .2 (4.2 ) Stock-based compensation deficiency (1.8 ) - Rate changes of prior year deferreds 4.2 .4 Increase in valuation allowance and other (42.0 ) (21.3 ) Total income tax expense - 5.0 %
Summary of deferred tax assets and liabilities	(in thousands) December 31, 2015 December 31, 2014 Deferred tax assets Net operating loss carryforwards $ 5,433 $ 2,622 Depletion carryforwards 2,570 2,347 Accrual and other 1,318 1,242 Derivatives (213 ) (496 ) Asset retirement obligations 1,168 1,118 Property, plant and equipment 7,185 7,011 Total deferred tax assets 17,461 13,844 Deferred tax liability Interest in partnerships (757 ) (628 ) Less valuation allowance (16,704 ) (13,216 ) Net deferred tax asset $ - $ -

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Class Of Stock [Line Items]
Summary of number of shares and exercise price of options outstanding and exercisable	Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life (Years) Outstanding – January 1, 2014 163,076 $ 0.61 2.0 Outstanding – December 31, 2014 163,076 0.61 1.0 Outstanding – December 31, 2015 163,076 0.61 0.0 Exercisable – December 31, 2015 163,076 $ 0.61 0.0
Restricted Performance Units [Member]
Class Of Stock [Line Items]
Summary of Company's unvested restricted stock	Number of Shares Restricted performance units, non-vested, January 1, 2014 3,086,160 Granted 1,600,000 Restricted performance units, non-vested, December 31, 2014 4,686,160 Granted 1,600,000 Restricted performance units, non-vested, December 31, 2015 6,286,160
Carbon 2011 Stock Incentive Plan [Member]
Class Of Stock [Line Items]
Summary of Company's unvested restricted stock	Weighted Avg Number Grant Date of Shares Fair Value Restricted stock awards, nonvested, January 1, 2014 2,780,003 $ 0.63 Granted 1,600,000 0.59 Vested (856,662 ) 0.63 Restricted stock awards, nonvested, December 31, 2014 3,523,341 0.61 Granted 1,740,000 0.40 Vested (1,283,341 ) 0.62 Restricted stock awards, nonvested, December 31, 2015 3,980,000 $ 0.52

Accounts Payable and Accrued 27

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Accounts Payable and Accrued Liabilities [Abstract]
Summary of accounts payable and accrued liabilities	(in thousands) As of December 31, 2015 2014 Accounts payable $ 577 $ 742 Oil and gas revenue payable to oil and gas property owners 1,221 1,296 Production taxes payable 59 132 Drilling advances received from joint venture partner 2,115 2,354 Accrued drilling costs 112 166 Accrued lease operating costs 76 74 Accrued ad valorem taxes 496 1,194 Accrued general and administrative expenses 833 1,247 Accrued income taxes payable - 377 Other liabilities 132 210 Total accounts payable and accrued liabilities $ 5,621 $ 7,792

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Summary of financial assets and liabilities at fair value	(in thousands) Fair Value Measurements Using Level 1 Level 2 Level 3 Total December 31, 2015 Assets: Commodity derivatives $ - $ 559 $ - $ 559 December 31, 2014 Assets: Commodity derivatives $ - $ 1,322 $ - $ 1,322

Physical Delivery Contracts a29

Physical Delivery Contracts and Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Schedule of future production volumes to be delivered and sold	Daily Volume Period (Dths per day) Price Contract 1 Jan – Mar 2016 1,300 Index less $0.36 Contract 2 Jan – Sep 2016 611 98% of Index less $0.23
Schedule of swap agreements	Natural Gas Oil Weighted Weighted Average Average Quarter MMBtu Price (a)(c) Bbl Price (b)(c) Swaps: Jan - Mar 2016 60,000 $ 3.66 - - Apr - Jun 2016 40,000 $ 3.39 - - Jul - Sep 2016 30,000 $ 3.12 - - Oct - Dec 2016 30,000 $ 3.12 - - Jan - Mar 2017 30,000 $ 3.27 - - Apr - Jun 2017 30,000 $ 3.27 - - Jul - Sep 2017 30,000 $ 3.27 - - Oct - Dec 2017 30,000 $ 3.27 - - Collars: Jan – Mar 2016 30,000 $ 2.75-$3.40 6,000 $50.00-$59.00 Apr – Jun 2016 30,000 $ 2.75-$3.40 6,000 $50.00-$59.00 Jul – Sep 2016 30,000 $ 2.75-$3.40 5,500 $48.64-$57.91 Oct – Dec 2016 30,000 $ 2.75-$3.40 4,500 $48.33-$58.00 Jan – Mar 2017 - - 4,500 $48.33-$61.67 Apr – Jun 2017 - - 4,500 $48.33-$61.67 Jul – Sep 2017 - - 4,500 $48.33-$61.67 Oct – Dec 2017 - - 4,500 $48.33-$61.67 (a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month. (b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month. (c) NYMEX costless collar floor and ceiling prices.
Schedule of fair value of the derivatives recorded	(in thousands) As of December 31, 2015 2014 Commodity derivative contracts: Current assets $ 408 $ 1,322 Non-current assets $ 151 $ -
Schedule of realized and unrealized gains and losses	(in thousands) For the year ended December 31, 2015 2014 Commodity derivative contracts: Settlement gains (losses) $ 1,615 $ (402 ) Unrealized (losses) gains (763 ) 1,648 Total settlement and unrealized gains, net $ 852 $ 1,246
Schedule of fair value amounts of all derivative instruments assets and liabilities	Net Gross Recognized Recognized Gross Fair Value Assets/ Amounts Assets/ Balance Sheet Classification Liabilities Offset Liabilities Commodity derivative assets: Current assets $ 429 $ (21 ) $ 408 Other long-term assets 194 (43 ) 151 Total derivative assets $ 623 $ (64 ) $ 559 Commodity derivative liabilities: Current liability $ 21 $ (21 ) $ - Non-current liabilities 43 (43 ) - Total derivative liabilities $ 64 $ (64 ) $ -

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies [Abstract]
Summary of firm transportation volumes and related demand charges	Period Dekatherms per day Demand Charges Jan 2016 - Apr 2018 4,450 $ 0.20 - $0.65 May 2018 - May 2020 2,150 $ 0.20 Jun 2020 – May 2036 1,000 $ 0.20

Supplemental Cash Flow Disclo31

Supplemental Cash Flow Disclosure (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Disclosure [Abstract]
Summary of supplemental cash flow disclosures	(in thousands) For the Year Ended December 31, 2015 2014 Cash paid during the period for: Interest payments $ 166 $ 482 Income taxes 325 - Non-cash transactions: Increase in net asset retirement obligations $ 4 $ 152 Decrease in accounts payable and accrued liabilities included in oil and gas properties $ (215 ) $ (930 )

Supplemental Financial Data -32

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) [Abstract]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells	2015 2014 Oil Natural Gas Total Oil Natural Gas Total MBbls MMcf MMcfe MBbls MMcf MMcfe Proved reserves, beginning of year 853 36,948 42,066 822 36,684 41,616 Revisions of previous estimates (185 ) (4,670 ) (5,780 ) (40 ) 2,358 2,118 Extensions and discoveries 31 - 186 205 44 1,274 Production (101 ) (2,040 ) (2,646 ) (134 ) (2,138 ) (2,942 ) Purchases of reserves in-place - 138 138 - - - Sales of reserves in-place - (418 ) (418 ) - - - Proved reserves, end of year 598 29,958 33,546 853 36,948 42,066 Proved developed reserves at: End of Year 554 29,958 33,282 770 35,935 40,555 Proved undeveloped reserves at: End of Year 44 - 264 83 1,013 1,511
Summary of aggregate capitalized costs relating to oil and gas producing activities	2015 2014 (in thousands) Oil and gas properties Proved oil and gas properties $ 97,453 $ 95,233 Unproved properties not subject to depletion 3,194 2,789 Accumulated depreciation, depletion, amortization and impairment (72,421 ) (64,535 ) Net oil and gas properties $ 28,226 $ 33,487
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities	2015 2014 (in thousands) Property acquisition costs: Unevaluated properties $ 341 $ 2,165 Proved properties and gathering facilities - 78 Development costs 2,106 8,685 Gathering facilities 578 144 Asset retirement obligation 4 152 Total costs incurred $ 3,029 $ 11,224
Summary of company's investment in unproved properties	2015 2014 2013 and Prior (in thousands) Acquisition costs $ 341 $ 1,762 $ 1,091
Summary of results of operations from oil and gas producing activities	2015 2014 (in thousands) Oil and gas sales, including commodity derivative gains $ 11,560 $ 23,789 Expenses: Production expenses 5,507 6,797 Depletion expense 2,466 2,800 Accretion of asset retirement obligations 123 117 Impairment of oil and gas properties 5,419 - Total expenses 13,515 9,714 Results of operations from oil and gas producing activities $ (1,955 ) $ 14,075 Depletion rate per Mcfe $ 0.93 $ 0.95
Summary of estimate of the current market value of the Company's proved reserves	December 31, 2015 2014 (in thousands) Future cash inflows $ 102,741 $ 250,659 Future production costs (47,117 ) (96,035 ) Future development costs (420 ) (3,908 ) Future income taxes - (32,234 ) Future net cash flows 55,204 118,482 10% annual discount (30,172 ) (53,476 ) Standardized measure of discounted future net cash flows $ 25,032 $ 65,006
Summary of discounted future cash flows relating to proved oil and gas reserves	December 31, 2015 2014 (in thousands) Standardized measure of discounted future net cash flows, beginning of year $ 65,006 $ 56,442 Sales of oil and gas, net of production costs and taxes (5,283 ) (15,746 ) Price revisions (37,490 ) 10,220 Extensions, discoveries and improved recovery, less related costs 384 6,561 Changes in estimated future development costs 3,290 959 Development costs incurred during the period - 1,010 Quantity revisions (4,282 ) 3,490 Accretion of discount 6,702 5,644 Net changes in future income taxes 2,010 (2,010 ) Purchases of reserves-in-place 115 - Sales of reserves-in-place (380 ) - Changes in production rate timing and other (5,040 ) (1,564 ) Standardized measure of discounted future net cash flows, end of year $ 25,032 $ 65,006
Summary of weighted averaged adjusted prices	2015 2014 Oil (per Bbl) $ 46.12 $ 92.10 Natural Gas (per Mcf) $ 2.50 $ 4.64

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Concentration Risk [Line Items]
Percentages by purchaser	10.00%	10.00%
Purchaser A [Member]
Concentration Risk [Line Items]
Percentages by purchaser	24.00%	29.00%
Purchaser B [Member]
Concentration Risk [Line Items]
Percentages by purchaser	18.00%	20.00%
Purchaser C [Member]
Concentration Risk [Line Items]
Percentages by purchaser	15.00%	13.00%
Purchaser D [Member]
Concentration Risk [Line Items]
Percentages by purchaser	15.00%	11.00%

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of reconciliation of the ARO
Balance at beginning of year	$ 2,968	$ 2,699
Accretion expense	123	117
Additions during period	4	152
Balance at end of year	$ 3,095	$ 2,968

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Net (loss) income	$ (8,298)	$ 6,941
Basic weighted-average common shares outstanding during the period	106,700	108,988
Add dilutive effects of stock options, warrants and non-vested shares of restricted stock		5,036
Diluted weighted-average common shares outstanding during the period	106,700	114,024
Basic net (loss) income per common share	$ (0.08)	$ 0.06
Diluted net (loss) income per common share	$ (0.08)	$ 0.06

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2015USD ($)Partnershipshares	Dec. 31, 2014USD ($)shares
Summary of Significant Accounting Policies (Textual)
Number of consolidated partnerships | Partnership	46
Cost method investments, additional information	The Company has less than 20% of the voting interests of a corporate affiliate or less than 5% interest of a partnership or limited liability company and does not have significant influence.
Equity method investment, additional information	If the Company holds between 20% and 50% of the voting interest in non-consolidated corporate affiliates or greater than a 5% interest of a partnership or limited liability company and exercises significant influence or control, the equity method of accounting is used to account for the investment.
Percentages by purchaser	10.00%	10.00%
Purchaser imbalance liability | $	$ 270,000	$ 182,000
Ceiling test impairment cost | $	$ 5,400,000
Warrant [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares	250,000	2,700,000
Stock Options [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares	163,000
Restricted Stock [Member]
Summary of Significant Accounting Policies (Textual)
Anti-dilutive earnings per shares	5,000,000
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies	6,300,000	4,700,000
Nytis LLC [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary	99.00%
Nytis USA [Member]
Summary of Significant Accounting Policies (Textual)
Percentage of ownership interest in the subsidiary	100.00%

Dispositions and Acquisitions (

Dispositions and Acquisitions (Details)	Oct. 31, 2015USD ($)	Dec. 31, 2014USD ($)Well	Dec. 31, 2015USD ($)
Dispositions and Acquisitions (Textual)
Amount received for the sale of interests	$ 145,000
Participation Agreement [Member]
Dispositions and Acquisitions (Textual)
Payment to Nytis LLC under agreement		$ 2,800,000
Working interest percentage in covered leases, Nytis LLC assigned to Liberty		40.00%
Number of wells drilled under participation agreement | Well		20
Nytis LLC [Member]
Dispositions and Acquisitions (Textual)
Cash transferred		$ 12,400,000
Addition cash received			$ 42,000

Property and Equipment (Details

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and gas properties
Accumulated depreciation, depletion, amortization and impairment	$ (72,421)	$ (64,535)
Net oil and gas properties	28,226	33,487
Furniture and fixtures, computer hardware and software, and other equipment	825	1,131
Accumulated depreciation and amortization	(587)	(827)
Net other property and equipment	238	304
Total net property and equipment	28,464	33,791
Proved oil and gas properties [Member]
Oil and gas properties
Oil and gas properties, gross	97,453	95,233
Unproved properties not subject to depletion [Member]
Oil and gas properties
Oil and gas properties, gross	$ 3,194	$ 2,789

Property and Equipment (Detai39

Property and Equipment (Details 1) - Unproved properties not subject to depletion [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	$ 3,194	$ 2,789
Indiana [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	433	433
Illinois [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	309	420
Kentucky [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	1,523	1,142
Ohio [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	66	66
West Virginia [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Oil and gas properties, gross	$ 863	$ 728

Property and Equipment (Detai40

Property and Equipment (Details Textual)	12 Months Ended
	Dec. 31, 2015USD ($)Per_Mcfe	Dec. 31, 2014USD ($)Per_Mcfe
Property and Equipment (Textual)
Proved property	$ 189,000	$ 194,000
Capitalized overhead	576,000	520,000
Depletion expense related to oil and gas properties	$ 2,500,000	$ 2,800,000
Depletion expense related to oil and gas properties (in dollars per Mcfe) | Per_Mcfe	0.93	0.95
Depreciation and amortization expense	$ 140,000	$ 154,000
Unproved properties not subject to depletion [Member]
Property and Equipment (Textual)
Depletion expense related to oil and gas properties	$ 3,200,000	$ 2,800,000

Equity Method Investment (Detai

Equity Method Investment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investment (Textual)
Ownership interest percentage in crawford county gas gathering company, LLC	50.00%
Equity investment income (loss) in crawford county gas gathering company, LLC	$ 16	$ 8

Bank Credit Facility (Details)

Bank Credit Facility (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Bank Credit Facility (Textual)
Current borrowing base	$ 20
Maximum line of credit available under hedging arrangements	$ 9.5
Line of credit facility maturity date	May 31, 2017
Maximum borrowing base	$ 50
Outstanding borrowings	3.5
Additional borrowing capacity available	$ 16.5
Effective borrowing rate (as a percent)	2.80%
Minimum [Member]
Bank Credit Facility (Textual)
Current ratio required to be maintained	1
Funded Debt Ratio required to be maintained	1
Maximum [Member]
Bank Credit Facility (Textual)
Current ratio required to be maintained	1
Funded Debt Ratio required to be maintained	4.25
Credit facility [Member]
Bank Credit Facility (Textual)
Variable interest rate basis	The portion of the loan based on an "Alternate Base Rate" is determined by the rate per annum equal to 1.5% plus the greatest of the following: (a) the Federal Funds Rate for such day plus one-half of one percentage point, (b) the Prime Rate for such day or (c) LIBOR for a one-month LIBOR Interest Period plus one percentage point.
Credit facility [Member] | LIBOR [Member] | Minimum [Member]
Bank Credit Facility (Textual)
Percentage points added to the reference rate	2.50%
Credit facility [Member] | LIBOR [Member] | Maximum [Member]
Bank Credit Facility (Textual)
Percentage points added to the reference rate	3.25%

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of provision for income taxes
Current income tax expense		$ 377
Deferred income tax expense	$ (3,733)	1,624
Change in valuation allowance	$ 3,773	(1,624)
Total income tax expense		$ 377

Income Taxes (Details 1)

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate
Federal income tax rate	35.00%	35.00%
State income taxes, net of federal benefit	3.50%	3.40%
Percentage depletion in excess of basis	1.30%	(7.20%)
Non-controlling interest in consolidated partnerships	(0.40%)	(1.10%)
True-up of prior year depletion in excess of basis	0.20%	(4.20%)
Stock-based compensation deficiency	(1.80%)
Rate changes of prior year deferreds	4.20%	0.40%
Increase in valuation allowance and other	(42.00%)	(21.30%)
Total income tax expense		5.00%

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets
Net operating loss carryforwards	$ 5,433	$ 2,622
Depletion carryforwards	2,570	2,347
Accrual and other	1,318	1,242
Derivatives	(213)	(496)
Asset retirement obligations	1,168	1,118
Property, plant and equipment	7,185	7,011
Total deferred tax assets	17,461	13,844
Deferred tax liability
Interest in partnerships	(757)	(628)
Less valuation allowance	$ (16,704)	$ (13,216)
Net deferred tax asset

Income Taxes (Details Textual)

Income Taxes (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Income Taxes (Textual)
Net operating losses	$ 12.6
Operating loss expiration year	Dec. 31, 2034
Net operating losses carryforward	$ 25

Stockholders' Equity (Details)

Stockholders' Equity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award Options [Abstract]
Number of Shares Outstanding, Beginning balance	163,076	163,076
Number of Shares Outstanding, Ending Balance	163,076	163,076	163,076
Number of Shares Exercisable	163,076
Weighted Average Exercise Price Options Outstanding, Beginning Balance	$ 0.61	$ 0.61
Weighted Average Exercise Price Options Outstanding, Ending Balance	0.61	$ 0.61	$ 0.61
Weighted Average Exercise Price Options Exercisable	$ 0.61
Weighted Average Remaining Contractual Life (Years) Options Outstanding	0 years	1 year	2 years
Weighted Average Remaining Contractual Life (Years) Options Exercisable	0 years

Stockholders' Equity (Details 1

Stockholders' Equity (Details 1) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Restricted Performance Units [Member]
Class Of Stock [Line Items]
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	4,686,160	3,086,160
Granted, Number of Shares	1,600,000	1,600,000
Restricted stock awards, nonvested, Ending Balance, Number of Shares	6,286,160	4,686,160
Carbon 2011 Stock Incentive Plan [Member]
Class Of Stock [Line Items]
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	3,523,341	2,780,003
Granted, Number of Shares	1,740,000	1,600,000
Vested, Number of Shares	(1,283,341)	(856,662)
Restricted stock awards, nonvested, Ending Balance, Number of Shares	3,980,000	3,523,341
Restricted stock awards, nonvested, Beginning Balance, Weighted Avg Grant Due Fair Value	$ 0.61	$ 0.63
Granted, Weighted Avg Grant Due Fair Value	0.40	0.59
Vested, Weighted Avg Grant Due Fair Value	0.62	0.63
Restricted stock awards, nonvested, Ending Balance, Weighted Avg Grant Due Fair Value	$ 0.52	$ 0.61

Stockholders' Equity (Details T

Stockholders' Equity (Details Textual) - USD ($)	Jun. 25, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Stockholders' Equity (Textual)
Common stock, shares authorized		200,000,000	200,000,000
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Common stock, shares issued		107,655,916	106,875,447
Common stock, shares outstanding		107,655,916	106,875,447
Preferred stock, shares authorized		1,000,000	1,000,000
Preferred stock, par value (in dollars per share)		$ 0.01	$ 0.01
Preferred stock, shares issued
Preferred stock, shares outstanding
Number of shares outstanding		163,076	163,076		163,076
Number of shares exercisable		163,076
Compensation costs for restricted stock grants		$ 335,000	$ 335,000
Unrecognized compensation cost		$ 335,000
Grant date fair value		$ 0.40	$ 0.59	$ 0.64
Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants		$ 762,000	$ 811,000
Expected period of recognition of unrecognized compensation costs		6 years 3 months 18 days
Restricted Stock [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost		$ 1,300,000
Restricted stock awards vest peroid		3 years
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants		$ 346,000	346,000
Unrecognized compensation cost		$ 127,000	$ 3,100,000	$ 3.1
Expected period of recognition of unrecognized compensation costs		4 months
Number of shares of unvested restricted stock granted		1,600,000	1,600,000
Grant date fair value		$ 0.54
Expected volatility rate		92.92%
Risk free interest rate		0.39%
Expected term		2 years 10 months 13 days
Equity Plans Prior To Merger [Member] | Stock Options [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		163,000
Number of shares exercisable		163,000
Equity Plans Prior To Merger [Member] | Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		250,000
Number of shares exercisable		250,000
Equity Plans Prior To Merger [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		979,000
Nytis USA Restricted Stock Plan [Member]
Stockholders' Equity (Textual)
Vesting terms of restricted stock		The vesting terms of these restricted stock grants were modified so that 25% of the shares would vest on the first of January from 2014 through 2017.
Vesting, percentage	25.00%
Nytis USA Restricted Stock Plan [Member] | Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares of unvested restricted stock granted		979,000
Carbon Stock Incentive Plans [Member] | Officer [Member]
Stockholders' Equity (Textual)
Stock incentive plan, common stock shares authorized		22,600,000
Nytis USA [Member] | Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		250,000
Number of shares exercisable		250,000
Exercise price		$ 1
Expiration date		Aug. 31, 2017

Accounts Payable and Accrued 50

Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounts Payable and Accrued Liabilities [Abstract]
Accounts payable	$ 577	$ 742
Oil and gas revenue payable to oil and gas property owners	1,221	1,296
Production taxes payable	59	132
Drilling advances received from joint venture partner	2,115	2,354
Accrued drilling costs	112	166
Accrued lease operating costs	76	74
Accrued ad valorem taxes	496	1,194
Accrued general and administrative expenses	$ 833	1,247
Accrued income taxes payable		377
Other liabilities	$ 132	210
Total accounts payable and accrued liabilities	$ 5,621	$ 7,792

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets:
Commodity derivatives	$ 408	$ 1,322
Recurring basis [Member] | Level 1 [Member]
Assets:
Commodity derivatives
Recurring basis [Member] | Level 2 [Member]
Assets:
Commodity derivatives	$ 559	$ 1,322
Recurring basis [Member] | Level 3 [Member]
Assets:
Commodity derivatives

Fair Value Measurements (Deta52

Fair Value Measurements (Details Textual) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Fair Value Measurements (Textual)
Asset retirement obligation	$ 4,000	$ 152,000

Physical Delivery Contracts a53

Physical Delivery Contracts and Commodity Derivatives (Details)	12 Months Ended
	Dec. 31, 2015Volume
Contract 1 [Member] | Jan - Mar 2016 [Member]
Derivatives, Fair Value [Line Items]
Daily Volume (Dths per day)	1,300
Price	Index less $0.36
Contract 2 [Member] | Jan - Sep 2016 [Member]
Derivatives, Fair Value [Line Items]
Daily Volume (Dths per day)	611
Price	98% of Index less $0.23

Physical Delivery Contracts a54

Physical Delivery Contracts and Commodity Derivatives (Details 1)	Dec. 31, 2015USD_MMBtuUSD_Bbl$ / shares
Swaps [Member] | Jan - Mar 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	60,000
Weighted Average Price	$ 3.66	[1],[2]
Swaps [Member] | Jan - Mar 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	40,000
Weighted Average Price	$ 3.39	[1],[2]
Swaps [Member] | Apr - Jun 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.12	[1],[2]
Swaps [Member] | Jul - Sep 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.12	[1],[2]
Swaps [Member] | Oct - Dec 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Jan - Mar 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swaps [Member] | Jan - Mar 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Apr - Jun 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swaps [Member] | Apr - Jun 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Jul - Sep 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swaps [Member] | Jul - Sep 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[2],[3]
Swaps [Member] | Oct - Dec 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Weighted Average Price	$ 3.27	[1],[2]
Swaps [Member] | Oct - Dec 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl
Weighted Average Price		[1],[2]
Collars [Member] | Jan - Mar 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Jan - Mar 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Jan - Mar 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Jan - Mar 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	6,000
Collars [Member] | Jan - Mar 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 50	[2],[3]
Collars [Member] | Jan - Mar 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 59	[2],[3]
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Apr - Jun 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	6,000
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 50	[2],[3]
Collars [Member] | Apr - Jun 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 59	[2],[3]
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Jul - Sep 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	5,500
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.64	[2],[3]
Collars [Member] | Jul - Sep 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 57.91	[2],[3]
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu	30,000
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 2.75	[1],[2]
Collars [Member] | Oct - Dec 2016 [Member] | Natural Gas [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 3.40	[1],[2]
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Oct - Dec 2016 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 58	[2],[3]
Collars [Member] | Jan - Mar 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Jan - Mar 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Apr - Jun 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Apr - Jun 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Jul - Sep 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Jul - Sep 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
Collars [Member] | Oct - Dec 2017 [Member] | Natural Gas [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_MMBtu
Weighted Average Price		[1],[2]
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member]
Derivative Instrument Detail [Abstract]
Quantity | USD_Bbl	4,500
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member] | Minimum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 48.33	[2],[3]
Collars [Member] | Oct - Dec 2017 [Member] | Oil [Member] | Maximum [Member]
Derivative Instrument Detail [Abstract]
Weighted Average Price	$ 61.67	[2],[3]
[1]	NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.
[2]	NYMEX costless collar floor and ceiling prices.
[3]	NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month.

Physical Delivery Contracts a55

Physical Delivery Contracts and Commodity Derivatives (Details 2) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Commodity derivative contracts:
Current assets	$ 408	$ 1,322
Non-current assets	$ 151

Physical Delivery Contracts a56

Physical Delivery Contracts and Commodity Derivatives (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Commodity derivative contracts:
Unrealized (losses) gains	$ (763)	$ 1,648
Commodity derivative contracts [Member]
Commodity derivative contracts:
Settlement gains (losses)	1,615	(402)
Unrealized (losses) gains	(763)	1,648
Total settlement and unrealized gains, net	$ 852	$ 1,246

Physical Delivery Contracts a57

Physical Delivery Contracts and Commodity Derivatives (Details 4) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Commodity derivative assets:
Current assets	$ 408	$ 1,322
Other long-term assets	151
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Current assets	429
Other long-term assets	194
Total derivative assets	623
Commodity derivative liabilities:
Current liability	21
Non-current liabilities	43
Total derivative liabilities	64
Gross Amounts Offset [Member]
Commodity derivative assets:
Current assets	(21)
Other long-term assets	(43)
Total derivative assets	(64)
Commodity derivative liabilities:
Current liability	(21)
Non-current liabilities	(43)
Total derivative liabilities	(64)
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Current assets	408
Other long-term assets	151
Total derivative assets	$ 559
Commodity derivative liabilities:
Current liability
Non-current liabilities
Total derivative liabilities

Commitments and Contingencies58

Commitments and Contingencies (Details)	12 Months Ended
	Dec. 31, 2015Per_McfePartnership
Jan 2016 - Apr 2018 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	4,450
Jan 2016 - Apr 2018 [Member] | Maximum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.65
Jan 2016 - Apr 2018 [Member] | Minimum [Member]
Other Commitments [Line Items]
Demand charges (in dollars per dekatherm)	0.20
May 2018 - May 2020 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	2,150
Demand charges (in dollars per dekatherm)	0.20
Jun 2020 - May 2036 [Member]
Other Commitments [Line Items]
Capacity levels (Dekatherms per day) | Partnership	1,000
Demand charges (in dollars per dekatherm)	0.20

Commitments and Contingencies59

Commitments and Contingencies (Details Textual)	12 Months Ended
	Dec. 31, 2015USD ($)ft²	Dec. 31, 2014USD ($)
Commitments and Contingencies (Textual)
Liability related to firm transportation contracts assumed	$ 852,000
Operating lease expiration date	Dec. 31, 2016
Rental expenses	$ 236,000	$ 207,000
Minimum lease payments 2016	176,000
Minimum lease payments 2017	3,000
Minimum lease payments 2018	$ 2,000
Colorado [Member]
Commitments and Contingencies (Textual)
Office space | ft²	5,500
Kentucky [Member]
Commitments and Contingencies (Textual)
Office space | ft²	5,300

Retirement Savings Plan (Detail

Retirement Savings Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Retirement Savings Plan [Abstract]
Matching percentage under retirement savings plan	6.00%
401(K) contributions and related administrative expenses	$ 277,000	$ 249,000

Supplemental Cash Flow Disclo61

Supplemental Cash Flow Disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash paid during the period for:
Interest payments	$ 166	$ 482
Income taxes	325
Non-cash transactions:
Increase in net asset retirement obligations	4	$ 152
Decrease in accounts payable and accrued liabilities included in oil and gas properties	$ (215)	$ (930)

Supplemental Financial Data -62

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details)	12 Months Ended
	Dec. 31, 2015MMcfMMBbls	Dec. 31, 2014MMcfMMBbls
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	42,066	41,616
Revisions of previous estimates	(5,780)	2,118
Extensions and discoveries	186	1,274
Production	(2,646)	(2,942)
Purchases of reserves in-place	138
Sales of reserves in-place	(418)
Proved reserves, end of year	33,546	42,066
Proved developed reserves at:
End of Year	33,282	40,555
Proved undeveloped reserves at:
End of Year	264	1,511
Oil [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year | MMBbls	853	822
Revisions of previous estimates | MMBbls	(185)	(40)
Extensions and discoveries | MMBbls	31	205
Production | MMBbls	(101)	(134)
Purchases of reserves in-place | MMBbls
Sales of reserves in-place | MMBbls
Proved reserves, end of year | MMBbls	598	853
Proved developed reserves at:
End of Year | MMBbls	554	770
Proved undeveloped reserves at:
End of Year | MMBbls	44	83
Natural Gas [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	36,948	36,684
Revisions of previous estimates	(4,670)	2,358
Extensions and discoveries		44
Production	(2,040)	(2,138)
Purchases of reserves in-place	138
Sales of reserves in-place	(418)
Proved reserves, end of year	29,958	36,948
Proved developed reserves at:
End of Year	29,958	35,935
Proved undeveloped reserves at:
End of Year		1,013

Supplemental Financial Data -63

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and gas properties
Proved oil and gas properties	$ 97,453	$ 95,233
Unproved properties not subject to depletion	3,194	2,789
Accumulated depreciation, depletion, amortization and impairment	(72,421)	(64,535)
Net oil and gas properties	$ 28,226	$ 33,487

Supplemental Financial Data -64

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property acquisition costs:
Unevaluated properties	$ 341	$ 2,165
Proved properties and gathering facilities		78
Development costs	$ 2,106	8,685
Gathering facilities	578	144
Asset retirement obligation	4	152
Total costs incurred	$ 3,029	$ 11,224

Supplemental Financial Data -65

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of company's investment in unproved properties
Acquisition costs	$ 341	$ 1,762	$ 1,091

Supplemental Financial Data -66

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 4) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)MMcf
Summary of results of operations from oil and gas producing activities
Oil and gas sales, including commodity derivative gains	$ 11,560	$ 23,789
Expenses:
Production expenses	5,507	6,797
Depletion expense	2,466	2,800
Accretion of asset retirement obligations	123	$ 117
Impairment of oil and gas properties	5,419
Total expenses	13,515	$ 9,714
Results of operations from oil and gas producing activities	$ (1,955)	$ 14,075
Depletion rate per Mcfe | MMcf	0.93	0.95

Supplemental Financial Data -67

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	$ 102,741	$ 250,659
Future production costs	(47,117)	(96,035)
Future development costs	$ (420)	(3,908)
Future income taxes		32,234
Future net cash flows	$ 55,204	118,482
10% annual discount	(30,172)	53,476
Standardized measure of discounted future net cash flows	$ 25,032	$ 65,006	$ 56,442

Supplemental Financial Data -68

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 6) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 65,006	$ 56,442
Sales of oil and gas, net of production costs and taxes	(5,283)	(15,746)
Price revisions	(37,490)	10,220
Extensions, discoveries and improved recovery, less related costs	384	6,561
Changes in estimated future development costs	$ 3,290	959
Development costs incurred during the period		1,010
Quantity revisions	$ (4,282)	3,490
Accretion of discount	6,702	5,644
Net changes in future income taxes	2,010	$ (2,010)
Purchases of reserves-in-place	115
Sales of reserves-in-place	(380)
Changes in production rate timing and other	(5,040)	$ (1,564)
Standardized measure of discounted future net cash flows, end of year	$ 25,032	$ 65,006

Supplemental Financial Data -69

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2015Per_McfeUSD_Bbl	Dec. 31, 2014Per_McfeUSD_Bbl
Oil (per Bbl) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | USD_Bbl	46.12	92.10
Natural Gas (per Mcf) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices | Per_Mcfe	2.50	4.64

Supplemental Financial Data -70

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Textual)
Estimated proved reserves	3.0 Bcfe	3.3 Bcfe
Discount rate, description	All cash flow amounts, including income taxes, are discounted at 10%.