Carbon Energy (CRBO) 10-K31 Mar 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Mar. 05, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Carbon Natural Gas Co
Entity Central Index Key	86264
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
Entity Well-Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$42.10
Entity Common Stock, Shares Outstanding		106,875,447

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$1,132	$243
Accounts receivable:
Revenue	2,287	2,551
Joint interest billings and other	1,038	627
Commodity derivative asset	1,322
Prepaid expense, deposits and other current assets	141	95
Total current assets	5,920	3,516
Oil and gas properties, full cost method of accounting:
Proved, net	30,698	39,033
Unevaluated	2,789	2,235
Other property and equipment, net	304	287
Total property and equipment	33,791	41,555
Investments in affiliates (note 5)	1,009	1,002
Other long-term assets	911	688
Total assets	41,631	46,761
Current liabilities:
Accounts payable and accrued liabilities	7,792	6,605
Firm transportation contract obligations (note 12)	487	556
Commodity derivative liability		226
Total current liabilities	8,279	7,387
Non-current liabilities:
Commodity derivative liability		100
Firm transportation contract obligations (note 12)	852	1,340
Asset retirement obligation (note 2)	2,968	2,699
Notes payable (note 6)	2,100	12,789
Total non-current liabilities	5,920	16,928
Commitments (note 12)
Stockholders' equity:
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2014 and 2013
Common stock, $0.01 par value; authorized 200,000,000 shares, 106,875,447 and 114,470,223 shares issued and outstanding at December 31, 2014 and 2013, respectively	1,069	1,145
Additional paid-in capital	53,160	55,029
Accumulated deficit	-29,832	-36,773
Total Carbon stockholders' equity	24,397	19,401
Non-controlling interests	3,035	3,045
Total stockholders' equity	27,432	22,446
Total liabilities and stockholders' equity	$41,631	$46,761

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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	106,875,447	114,470,223
Common stock, shares outstanding	106,875,447	114,470,223

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Revenue:
Oil and gas	$22,505	$18,681
Commodity derivative gain (loss)	1,246	-459
Other income	325	416
Total revenue	24,076	18,638
Expenses:
Lease operating expenses	3,333	2,620
Transportation costs	1,808	1,609
Production and property taxes	1,656	1,258
General and administrative	6,133	5,151
Depreciation, depletion and amortization	2,954	2,922
Accretion of asset retirement obligations	117	138
Total expenses	16,001	13,698
Operating income	8,075	4,940
Other income and (expense):
Interest expense	-471	-581
Equity investment income (loss)	8	-91
Total other expense	-463	-672
Income before income taxes	7,612	4,268
Income tax expense:
Current	377
Net income	7,235	4,268
Net (income) loss attributable to non-controlling interests	-294	18
Net income attributable to controlling interest	$6,941	$4,286
Net income per common share:
Basic	$0.06	$0.04
Diluted	$0.06	$0.04
Weighted average common shares outstanding (in thousands):
Basic	108,988	112,479
Diluted	114,024	117,096

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-in Capital	Non-Controlling Interests	Accumulated Deficit
In Thousands, except Share data, unless otherwise specified	Total	Common Stock	Additional Paid-in Capital	Non-Controlling Interests	Accumulated Deficit
Beginning Balances at Dec. 31, 2012	$17,382	$1,158	$54,195	$3,088	($41,059)
Beginning Balances, (in shares) at Dec. 31, 2012		115,795
Stock-based compensation	913		913
Restricted stock activity including amendments, vesting and shares exchanged for tax withholding	-92	-13	-79
Restricted stock activity including amendments, vesting and shares exchanged for tax withholding (in shares)		-1,325
Non-controlling interest:
Distributions, net	-25			-25
Net income (loss)	4,268			-18	4,286
Ending Balances at Dec. 31, 2013	22,446	1,145	55,029	3,045	-36,773
Ending Balances, (in shares) at Dec. 31, 2013		114,470
Purchase of common stock	-3,261	-82	-3,179
Purchase of common stock (in shares)		-8,154
Stock-based compensation	1,492		1,492
Restricted stock activity including amendments, vesting and shares exchanged for tax withholding	-176	6	-182
Restricted stock activity including amendments, vesting and shares exchanged for tax withholding (in shares)		559
Non-controlling interest:
Distributions, net	-304			-304
Net income (loss)	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

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income	$7,235	$4,268
Items not involving cash:
Depreciation, depletion and amortization	2,954	2,922
Accretion of asset retirement obligations	117	138
Unrealized derivative (gain) loss	-1,648	239
Stock-based compensation expense	1,492	913
Equity investment (income) loss	-8	91
Net change in:
Accounts receivable	37	857
Prepaid expenses, deposits and other current assets	-46	20
Accounts payable, accrued liabilities and firm transportation contracts	1,563	-2,046
Due to/from related parties		446
Net cash provided by operating activities	11,696	7,848
Cash flows from investing activities:
Development of oil and gas properties and other capital expenditures	-9,001	-9,114
Acquisition of oil and gas properties	-2,244	-501
Proceeds from sale of oil and gas properties	15,276
Equity method investment		125
Other long-term assets	-408	-26
Net cash provided by (used in) investing activities	3,623	-9,516
Cash flows from financing activities:
Purchase of common stock	-3,261
Vested restricted stock exchanged for tax withholding	-176	-92
Proceeds from notes payable	5,700	2,700
Payments on notes payable	-16,389	-1,000
Distribution to non-controlling interests	-304	-25
Net cash (used in) provided by financing activities	-14,430	1,583
Net increase (decrease) in cash and cash equivalents	889	-85
Cash and cash equivalents, beginning of period	243	328
Cash and cash equivalents, end of period	$1,132	$243

Organization

Organization	12 Months Ended
Organization	Dec. 31, 2014
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_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 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 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, 2014 and 2013, 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, 2014 and 2013. 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		2014				2013
	Purchaser A			29	%			11	%
	Purchaser B			20	%			1	%
	Purchaser C			13	%			22	%
	Purchaser D			11	%			4	%
	Purchaser E			7	%			39	%



	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, 2014, the Company has a purchaser imbalance receivable of approximately $182,000 which is recognized as a current asset in the Company’s Consolidated Balance Sheet.



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 2014 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 years ended December 31, 2014 and 2013, 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.



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, 2014 and 2013.



		Year Ended
		December 31,
(in thousands)		2014				2013

Balance at beginning of year		$	2,699			$	2,321
Accretion expense			117				138
Additions during period			152				123
Additions assumed with acquired properties			-				117
Costs incurred			-				-

Balance at end of year		$	2,968			$	2,699



Financial Instruments



The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, derivative instruments and its credit facility. 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 derivative instruments are recorded at fair value, as discussed below and in Note 10. The carrying amount of the Company’s credit facility 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 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



The Company accounts for natural gas sales using the entitlements method. The Company accounts for oil sales when title to the product is transferred. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.



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 the 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 the options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).



For the years ended December 31, 2014 and 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million common stock equivalents that were out-of-the money, respectively and approximately 4.7 million and 3.2 million restricted performance units, respectively, 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 derivative instruments and asset retirement obligations. Actual results could differ from those estimates and assumptions used.



Adopted and Recently Issued Accounting Pronouncements



Effective October 1, 2014, the Company early adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU changed the criteria for reporting discontinued operations while enhancing disclosures in this area. There was no impact to the Company’s financial statements or disclosures from the early adoption of this standard.



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, 2016. 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 February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a retrospective method or 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, 2015. 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.

Dispositions_and_Acquisitions

Dispositions and Acquisitions	12 Months Ended
Dispositions and Acquisitions	Dec. 31, 2014
Dispositions and Acquisitions [Abstract]
Dispositions and Acquisitions	Note 3 – Dispositions and Acquisitions



	Liberty Participation Agreement



	On February 25, 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.



	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.



	Acquisitions



	In May 2013, in two separate transactions, the Company acquired proved producing oil and gas properties and additional interests in partnerships with proved producing properties located in Kentucky and West Virginia for a total purchase price of approximately $517,000.



	The purchase of these assets qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date (the date on which the Company obtained control of the properties.) The purchases of these assets were recorded as an investment in the Company’s proved oil and gas properties. There was no significant difference between the fair value of the assets and the purchase price.



	During 2013, for nominal cash and assumption of nominal partner liabilities, the Company acquired additional partnership interests from other partners.



	Divestitures



	On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).



	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.



	At the preliminary closing, the buyer provided to Sellers a description of title defects (many of which the parties considered to be readily curable) and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.



	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 PSA were recorded as a reduction of the Company’s investment in its proved and unevaluated oil and natural gas properties.

Property_and_Equipment

Property and Equipment	12 Months Ended
Property and Equipment	Dec. 31, 2014
Property and Equipment [Abstract]
Property and Equipment	Note 4 – Property and Equipment

	Net property and equipment at December 31, 2014 and 2013 consists of the following:

		As of December 31,
	(in thousands)	2014			2013

	Oil and gas properties:
	Proved oil and gas properties	$	95,233		$	100,769
	Unproved properties not subject to depletion		2,789			2,235
	Accumulated depreciation, depletion, amortization and impairment		(64,535	)		(61,736	)
	Net oil and gas properties		33,487			41,268

	Furniture and fixtures, computer hardware and software, and other equipment		1,131			960
	Accumulated depreciation and amortization		(827	)		(673	)
	Net other property and equipment		304			287

	Total net property and equipment	$	33,791		$	41,555

	The Company had approximately $2.8 million and $2.2 million, at December 31, 2014 and 2013, respectively, of unproved oil and gas properties not subject to depletion. At December 31, 2014 and 2013, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas:

		As of December 31,
	(in thousands)	2014			2013

	Illinois Basin:
	Indiana	$	433		$	446
	Illinois		420			354
	Appalachian Basin:
	Kentucky		1,142			1,367
	Ohio		66			66
	West Virginia		728			2

	Total unproved properties not subject to depletion	$	2,789		$	2,235

	During the years ended December 31, 2014 and 2013, expiring leasehold costs reclassified into proved property were approximately $194,000 and $4,000, 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. Subject to industry conditions, evaluation of most of these properties and the inclusion of their costs in amortized capital costs are expected to be completed within five years.

	The Company capitalized overhead applicable to acquisition, development and exploration activities of approximately $520,000 and $483,000 for the years ended December 31, 2014 and 2013, respectively.

	Depletion expense related to oil and gas properties for the years ended December 31, 2014 and 2013 was approximately $2.8 million for each year or $0.95 and $0.96 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, 2014 and 2013 was approximately $154,000 and $133,000, respectively.

Equity_Method_Investment

Equity Method Investment	12 Months Ended
Equity Method Investment	Dec. 31, 2014
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. During 2014 and 2013, the Company recorded equity method income of approximately $8,000 and loss of approximately $91,000, respectively, related to this investment.

Bank_Credit_Facility

Bank Credit Facility	12 Months Ended
Bank Credit Facility	Dec. 31, 2014
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; however, 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. Prior to July 2013, for all debt outstanding regardless if the loan was based on the Alternative Base Rate or LIBOR, there was a minimum floor of 4.5% per annum. On June 28, 2013, the Company and Bank of Oklahoma amended the credit agreement whereby the Company’s loans under the credit agreement are no longer subject to the minimum interest rate floor of 4.5% per annum for LIBOR tranches commencing after July 25, 2013 and for loan amounts subject to the Alternate Base Rate after July 31, 2013. 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, 2014, there were approximately $2.1 million in outstanding borrowings and approximately $17.9 million of additional borrowing capacity available under the credit facility. The Company’s effective borrowing rate at December 31, 2014 was approximately 3.0%. 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 and the payment of dividends, and requires satisfaction of a 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.



	The Company is in compliance with all covenants associated with the credit agreement as of December 31, 2014.

Income_Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2014
Income Taxes [Abstract]
Income Taxes	Note 7 – Income Taxes

	The provision for income taxes for the years ended December 31, 2014 and 2013 consists of the following:

		Year Ended
	(in thousands)	December 31, 2014			December 31, 2013

	Current income tax expense	$	377		$	-
	Deferred income tax expense		1,624			1,351
	Change in valuation allowance		(1,624	)		(1,351	)

	Total income tax expense	$	377		$	-

	The effective income tax rate for the years ended December 31, 2014 and 2013 differed from the statutory U.S. federal income tax rate as follows:

		Year Ended
		December 31, 2014			December 31, 2013

	Federal income tax rate		35	%		35	%
	State income taxes, net of federal benefit		3.4			3.7
	Percentage depletion in excess of basis		(7.2	)		(3.9	)
	Non-controlling interest in consolidated partnerships		(1.1	)		(1.3	)
	True-up of prior year depletion in excess of basis		(4.2	)		(5.7	)
	Rate changes of prior year deferreds		0.4			3.9
	Increase in valuation allowance and other		(21.3	)		(31.7	)

	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, 2014 and 2013 are presented below:

	(in thousands)	December 31, 2014			December 31, 2013

	Deferred tax assets
	Net operating loss carryforwards	$	2,622		$	6,754
	Depletion carryforwards		2,347			1,435
	Accrual and other		1,242			1,043
	Derivatives		(496	)		125
	Asset retirement obligations		1,118			1,024
	Property, plant and equipment		7,011			5,009
	Total deferred tax assets		13,844			15,390

	Deferred tax liability
	Interest in partnerships		(628	)		(475	)

	Less valuation allowance		(13,216	)		(14,915	)

	Net deferred tax asset	$	-		$	-

	The Company has net operating losses (“NOL”) of approximately $6.3 million available to reduce future years’ federal taxable income. The federal net operating losses expire in 2033. The Company has NOL of approximately $10 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, 2014, 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
Stockholders' Equity	Dec. 31, 2014
Stockholders' Equity [Abstract]
Stockholders' Equity	Note 8 – Stockholders’ Equity



	Authorized and Issued Capital Stock



	As of December 31, 2014, the Company had 200,000,000 shares of common stock authorized with a par value of $0.01 per share, of which 106,875,447 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, 2014, increases in the Company’s issued and outstanding common stock reflect restricted stock, net of shares exchanged for payroll tax obligation paid by the Company, that vested during the year. In addition, pursuant to a Stock Purchase Agreement dated June 9, 2014, the Company purchased approximately 8.2 million shares of the Company’s common stock from a shareholder for a purchase price of $0.40 per share. The purchase represented 100% of the shareholder’s holding of the Company’s common stock. These shares were cancelled and returned to the Company’s authorized stock and reduced the number of shares issued and outstanding.



	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, 2014, the Company has 163,076 options outstanding and exercisable, 2,696,133 warrants (including 250,000 warrants granted by SLSC prior to the merger) outstanding and exercisable and 1,468,181 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, 2014 and 2013. 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, 2013			163,076		$	0.61	3

	Outstanding – December 31, 2013			163,076			0.61	2

	Outstanding – December 31, 2014			163,076			0.61	1

	Exercisable – December 31, 2014			163,076		$	0.61	1

	Nytis USA Warrants



	Prior to January 1, 2006, the Company granted 2,446,133 warrants to an officer of the Company. Any shares to be issued upon exercise of the warrants would be from newly issued shares. Utilizing the minimum valuation method under the Black-Scholes option price model, the Company determined that the fair value of the warrants at the date of grant was nil. Each warrant enabled the holder to purchase one share of common stock of the Company, at an initial exercise price of $0.61 per share of common stock until expiry on June 1, 2015. The initial warrant exercise price of $0.61 per share of common stock was to increase annually at 6% starting June 1, 2006 and the exercise price for each of the warrants at December 31, 2010 was $0.85. Pursuant to the merger, the exercise price was fixed at $0.85. Inclusive of 250,000 warrants granted by SLSC prior to the merger with an exercise price of $1.00 which expire on August 31, 2017, the Company has 2,696,133 warrants outstanding at December 31, 2014. The number of warrants have been adjusted in line with the exchange ratio of Nytis USA shares for Carbon shares in the merger.



	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, 2014, there were 1,468,181 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.



	On June 25, 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 and $168,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, there was approximately $671,000 of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 2 years.



Carbon Stock Incentive Plan



In 2011, the stockholders of Carbon approved the adoption of Carbon’s 2011 Stock Incentive Plan (“Carbon Plan”), under which 12,600,000 shares of common stock were authorized for issuance to Carbon officers, directors, employees or consultants eligible to receive awards under the Carbon Plan.

The Carbon Plan provides 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 and for 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 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 Plan as of December 31, 2014 and 2013 as well as activity during the years then ended.




					Weighted Avg
		Number			Grant Date
		of Shares			Fair Value
Restricted stock awards, nonvested, January 1, 2013			1,610,000		$	0.62

Granted			1,600,000		0.64

Vested			(429,997	)		0.62

Restricted stock awards, nonvested, December 31, 2013			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

Compensation costs recognized for these restricted stock grants were approximately $811,000 and $526,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, 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, 2014 and 2013 as well as activity during the years then ended.



		Number
		of Shares
Restricted performance units, non-vested, January 1, 2013			1,166,160

Granted			1,920,000

Restricted performance units, non-vested, December 31, 2013			3,086,160

Granted			1,600,000

Restricted performance units, non-vested, December 31, 2014			4,686,160



The Company accounts for the performance units granted during 2012 and 2014 at their fair value determined at the date of grant, which were $.64 and $.59 per share, respectively. The final measurement of compensation cost will be based on the number of performance units that ultimately vest. At December 31, 2014, the Company estimated that none of the performance units granted in 2012 and 2014 would vest due to change in control and other performance provisions and accordingly, no compensation cost has been recorded. As of December 31, 2014, 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 and 2014 would be approximately $2.2 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 and 2014, 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 and $218,000 for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, there was approximately $473,000 of unrecognized compensation costs related to the performance units granted in 2013. These costs are expected to be recognized over the next 1.3 years.

Accounts_Payable_and_Accrued_L

Accounts Payable and Accrued Liabilities	12 Months Ended
Accounts Payable and Accrued Liabilities	Dec. 31, 2014
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, 2014 and 2013 consist of the following:



		As of December 31,
	(in thousands)	2014		2013

	Accounts payable	$	742	$	2,151
	Oil and gas revenue payable to oil and gas property owners		1,296		1,307
	Production taxes payable		132		165
	Drilling advances received from joint venture partner		2,354		740
	Accrued drilling costs		166		162
	Accrued lease operating costs		74		42
	Accrued ad valorem taxes		1,194		681
	Accrued general and administrative expenses		1,247		1,146
	Accrued income taxes payable		377		-
	Other liabilities		210		211

	Total accounts payable and accrued liabilities	$	7,792	$	6,605

Fair_Value_Measurements

Fair Value Measurements

12 Months Ended

Dec. 31, 2014

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, 2014 and 2013 by level within the fair value hierarchy:

Fair Value Measurements Using

(in thousands)

Level 1

Level 2

Level 3

Total

31-Dec-14

Assets:

Commodity derivatives

1,322

31-Dec-13

Liabilities:

Commodity derivatives

326

As of December 31, 2014, the Company’s commodity derivative financial instruments are comprised of seven natural gas swap agreements and two oil swap agreements. As of December 31, 2013, the Company’s commodity derivative financial instruments were comprised of nine natural gas swap agreements and five oil swap agreements. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. 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, 2014 and 2013, the Company recorded asset retirement obligations for additions of approximately $152,000 and $240,000, respectively. See Note 2 for additional information.

To determine the fair value of the proved developed properties acquired, 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_an

Physical Delivery Contracts and Commodity Derivatives	12 Months Ended
Physical Delivery Contracts and Commodity Derivatives	Dec. 31, 2014
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.



	At December 31, 2014, the Company has a fixed price contract requiring physical deliveries for approximately 530 Bbl/month at an average sales price of $96.75 per Bbl from January 2015 through August 2015. The Company’s other oil and gas sales contracts approximate index prices.



	The Company’s swap agreements as of December 31, 2014 are summarized in the table below:



			Natural Gas						Oil
						Weighted						Weighted
						Average						Average
	Period		MMBtu			Price (a)			Bbl			Price (b)
	Jan - Mar 2015			220,000		$	4.06			5,000		$	94.52
	Apr - Jun 2015			170,000		$	4.04			3,000		$	94.8
	Jul - Sep 2015			180,000		$	4.05			2,000		$	94.8
	Oct - Dec 2015			180,000		$	4.05			-			-
	Jan - Mar 2016			30,000		$	4.2			-			-
	Apr-16			10,000		$	4.2			-			-



	(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.



	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,
			2014			2013
	Commodity derivative contracts:
	Current assets		$	1,322		$	-
	Current liabilities		$	-		$	226
	Non-current liabilities		$	-		$	100



	The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2014 and 2013. These realized and unrealized gains and losses are recorded and included in commodity derivative (loss) gain in the accompanying Consolidated Statements of Operations.



	(in thousands)		For the year ended
	(in thousands)		December 31,
			2014			2013
	Commodity derivative contracts:
	Realized (losses)		$	(402	)	$	(220	)
	Unrealized gains (losses)			1,648			(239	)

	Total realized and unrealized gains (losses), net		$	1,246		$	(459	)



Realized 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 Sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the Consolidated Balance Sheets:



										Net
				Gross						Recognized
				Recognized			Gross			Fair Value
				Assets/			Amounts			Assets/
		Balance Sheet Classification		Liabilities			Offset			Liabilities

Commodity derivative assets:		Current derivative asset		$	1,322		$	-		$	1,322

Total derivative assets				$	1,322		$	-		$	1,322



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

Commitments	12 Months Ended
	Dec. 31, 2014
Commitments [Abstract]
Commitments	Note 12 – Commitments

	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, 2014 are summarized in the table below.

	Period	Dekatherms per day		Demand Charges
	Jan 2015 - May 2015		5,950	$0.20 - $0.67
	Jun 2015 - Oct 2015		4,800	$0.22 - $0.67
	Nov 2015 - Dec 2017		3,300	$0.22 - $0.67
	Jan 2018 - May 2036		1,000	$0.22

	A liability of approximately $1.3 million related to firm transportation contracts assumed in a 2011 asset acquisition, which represents the remaining commitment, is reflected on the Company’s Consolidated Balance Sheets as of December 31, 2014. 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.

	The Company leases approximately 5,500 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2016 and approximately 5,300 square feet of office space in Lexington, Kentucky. For the years ended December 31, 2014 and 2013, the Company incurred rental expenses of $207,000 and $189,000, respectively. The Company has minimum lease payments for its office space and equipment of approximately $238,000 and $171,000 for 2015 and 2016, respectively.

Retirement_Savings_Plan

Retirement Savings Plan	12 Months Ended
Retirement Savings Plan	Dec. 31, 2014
Retirement Savings Plan [Abstract]
Retirement Savings Plan	Note 13 – Retirement Savings Plan



	The Company outsources certain payroll and human resource functions to an administrative company. In conjunction with this arrangement, 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, 2014 and 2013, the Company paid approximately $249,000 and $192,000, respectively, for 401(k) contributions and related administrative expenses.

Supplemental_Cash_Flow_Disclos

Supplemental Cash Flow Disclosures	12 Months Ended
Supplemental Cash Flow Disclosures	Dec. 31, 2014
Supplemental Cash Flow Disclosures [Abstract]
Supplemental Cash Flow Disclosures	Note 14 – Supplemental Cash Flow Disclosure



	Supplemental cash flow disclosures for the years ended December 31, 2014 and 2013 are presented below:



	(in thousands)	For the Year Ended
	(in thousands)	December 31,
		2014			2013

	Cash paid for interest payments	$	482		$	548

	Non-cash transactions:
	Increase (decrease) in net asset retirement obligations	$	152		$	240
	(Decrease) increase in accounts payable and accrued liabilities included in oil and gas properties	$	(932	)	$	1,046
	Receivables due from partners assumed in acquisitions	$	2		$	20

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note 15 – Subsequent Events

	On December 15, 2014, Nytis LLC together with Liberty, (the “Sellers”) completed a preliminary closing in accordance with a Purchase and Sale Agreement (the “PSA”) entered into on October 15, 2014, as amended, 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 (the “Leases”).

	At the preliminary closing, the buyer provided to Sellers a description of title defects (many of which the parties considered to be readily curable) and estimated that the extent of title defects was less than the twenty percent (20%) threshold provided in the PSA that would have permitted either buyer or Sellers to terminate the transaction.

	A final closing is scheduled for mid-April 2015 at which time the Sellers’ curative work and substitute acreage will be agreed to and may result in a downward revision of the purchase price.

Supplemental_Financial_Data_Oi

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2014
Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) [Abstract]
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	Note 16 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited)

	Estimated Proved Oil and Gas Reserves

	The reserve estimates as of December 31, 2014 and 2013 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, 2014 and 2013 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 2014 and 2013 are presented in the table below. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences 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, 2014 and 2013 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, 2014 and 2013. 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, 2014 and 2013. 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, 2014 and 2013 are as follows:

			2014											2013
			Oil				Natural Gas				Total			Oil			Natural Gas			Total
			MBbls				MMcf				MMcfe			MBbls			MMcf			MMcfe

	Proved reserves, beginning of year			822				36,684				41,616			872			33,646			38,878
	Revisions of previous estimates			(40	)			2,358				2,118			(249	)		3,459			1,965
	Extensions and discoveries			205				44				1,274			305			1,394			3,224
	Production			(134	)			(2,138	)			(2,942	)		(107	)		(2,252	)		(2,894	)
	Purchases of reserves in-place			-				-				-			1			437			443
	Sales of reserves in-place			-				-				-			-			-			-
	Proved reserves, end of year			853				36,948				42,066			822			36,684			41,616

	Proved developed reserves at:
	End of Year			770				35,935				40,555			748			35,317			39,805
	Proved undeveloped reserves at:
	End of Year			83				1,013				1,511			74			1,367			1,811

	The estimated proved reserves for December 31, 2014 and 2013 includes 3.3 Bcfe in each year attributed to non-controlling interests of consolidated partnerships.

	In 2013 revisions of previous oil estimates consisted of a decrease of approximately 109 MBbls associated with performance declines and a decrease of approximately 161 MBbls associated with proved undeveloped locations that were determined not to be viable. Revisions in 2014 and 2013 of previous estimates for natural gas are principally attributed to the increase in natural gas prices which extended the economic life of the wells.

	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:

			2014				2013
			(in thousands)
	Oil and gas properties
	Proved oil and gas properties		$	95,233			$	100,769
	Unproved properties not subject to depletion			2,789				2,235
	Accumulated depreciation, depletion, amortization and impairment			(64,535	)			(61,736	)
	Net oil and gas properties		$	33,487			$	41,268

	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, 2014 and 2013:

			2014				2013
			(in thousands)
	Property acquisition costs:
	Unevaluated properties		$	2,165			$	1,117
	Proved properties and gathering facilities			78				501
	Development costs			8,685				7,818
	Gathering facilities			144				1
	Asset retirement obligation			152				240
	Total costs incurred		$	11,224			$	9,677

	The Company’s investment in unproved properties as of December 31, 2014, by the year in which such costs were incurred is set forth in the table below:

		2014				2013				2012 and Prior
		(in thousands)

Acquisition costs		$	1,762			$	832			$	195

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities for the years ended December 31, 2014 and 2013 are presented below:

		2014				2013
		(in thousands)

Oil and gas sales, including commodity derivative gains		$	23,789			$	18,222
Expenses:
Production expenses			6,797				5,487
Depletion expense			2,800				2,789
Accretion of asset retirement obligations			117				138
Total expenses			9,714				8,414
Results of operations from oil and gas producing activities		$	14,075			$	9,808

Depletion rate per Mcfe		$	0.95			$	0.96
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,
		2014				2013
		(in thousands)

Future cash inflows		$	250,659			$	218,545
Future production costs			(96,035	)			(91,013	)
Future development costs			(3,908	)			(4,152	)
Future income taxes			(32,234	)			(13,920	)
Future net cash flows			118,482				109,460
10% annual discount			(53,476	)			(53,018	)
Standardized measure of discounted future net cash flows		$	65,006			$	56,442
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,
		2014				2013
		(in thousands)

Standardized measure of discounted future net cash flows, beginning of year		$	56,442			$	45,592
Sales of oil and gas, net of production costs and taxes			(15,746	)			(13,194	)
Price revisions			10,220				2,852
Extensions, discoveries and improved recovery, less related costs			6,561				10,869
Changes in estimated future development costs			959				980
Development costs incurred during the period			1,010				782
Quantity revisions			3,490				2,513
Accretion of discount			5,644				4,559
Net changes in future income taxes			(2,010	)			-
Purchases of reserves-in-place			-				293
Sales of reserves-in-place			-				-
Changes in production rates timing and other			(1,564	)			1,196
Standardized measure of discounted future net cash flows, end of year		$	65,006			$	56,442

The twelve month weighted averaged adjusted prices in effect at December 31, 2014 and 2013 were as follows:

		2014				2013
Oil (per Bbl)		$	92.1			$	94.08
Natural Gas (per Mcf)		$	4.64			$	3.84

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 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 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, 2014 and 2013, 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, 2014 and 2013. 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	2014			2013
	Purchaser A		29	%		11	%
	Purchaser B		20	%		1	%
	Purchaser C		13	%		22	%
	Purchaser D		11	%		4	%
	Purchaser E		7	%		39	%

	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, 2014, the Company has a purchaser imbalance receivable of approximately $182,000 which is recognized as a current asset in the Company’s Consolidated Balance Sheet.

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 2014 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 years ended December 31, 2014 and 2013, 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.
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, 2014 and 2013.



		Year Ended
		December 31,
	(in thousands)	2014			2013

	Balance at beginning of year	$	2,699		$	2,321
	Accretion expense		117			138
	Additions during period		152			123
	Additions assumed with acquired properties		-			117
	Costs incurred		-			-

	Balance at end of year	$	2,968		$	2,699
Financial Instruments	Financial Instruments



	The Company’s financial instruments include cash and cash equivalents, accounts receivables, accounts payables, accrued liabilities, derivative instruments and its credit facility. 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 derivative instruments are recorded at fair value, as discussed below and in Note 10. The carrying amount of the Company’s credit facility 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 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



	The Company accounts for natural gas sales using the entitlements method. The Company accounts for oil sales when title to the product is transferred. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.

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 the 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 the options and warrants (which were assumed to have been made at the average market price of the common shares during the reporting period).



	For the years ended December 31, 2014 and 2013, the diluted income per common share calculation excludes the dilutive effect of approximately 2.7 million common stock equivalents that were out-of-the money, respectively and approximately 4.7 million and 3.2 million restricted performance units, respectively, 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 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

	Effective October 1, 2014, the Company early adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.” This ASU changed the criteria for reporting discontinued operations while enhancing disclosures in this area. There was no impact to the Company’s financial statements or disclosures from the early adoption of this standard.

	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, 2016. 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 February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a retrospective method or 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, 2015. 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.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2014
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	2014			2013
	Purchaser A		29	%		11	%
	Purchaser B		20	%		1	%
	Purchaser C		13	%		22	%
	Purchaser D		11	%		4	%
	Purchaser E		7	%		39	%
Summary of reconciliation of the ARO		Year Ended
		December 31,
	(in thousands)	2014			2013

	Balance at beginning of year	$	2,699		$	2,321
	Accretion expense		117			138
	Additions during period		152			123
	Additions assumed with acquired properties		-			117
	Costs incurred		-			-

	Balance at end of year	$	2,968		$	2,699

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
Property and Equipment (Tables)	Dec. 31, 2014
Property and Equipment [Abstract]
Summary of net property and equipment		As of December 31,
	(in thousands)	2014			2013

	Oil and gas properties:
	Proved oil and gas properties	$	95,233		$	100,769
	Unproved properties not subject to depletion		2,789			2,235
	Accumulated depreciation, depletion, amortization and impairment		(64,535	)		(61,736	)
	Net oil and gas properties		33,487			41,268

	Furniture and fixtures, computer hardware and software, and other equipment		1,131			960
	Accumulated depreciation and amortization		(827	)		(673	)
	Net other property and equipment		304			287

	Total net property and equipment	$	33,791		$	41,555





Summary of unproved oil and gas properties		As of December 31,
	(in thousands)	2014			2013

	Illinois Basin:
	Indiana	$	433		$	446
	Illinois		420			354
	Appalachian Basin:
	Kentucky		1,142			1,367
	Ohio		66			66
	West Virginia		728			2

	Total unproved properties not subject to depletion	$	2,789		$	2,235

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2014
Income Taxes [Abstract]
Summary of provision for income taxes		Year Ended
	(in thousands)	December 31, 2014			December 31, 2013

	Current income tax expense	$	377		$	-
	Deferred income tax expense		1,624			1,351
	Change in valuation allowance		(1,624	)		(1,351	)

	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, 2014			December 31, 2013

	Federal income tax rate		35	%		35	%
	State income taxes, net of federal benefit		3.4			3.7
	Percentage depletion in excess of basis		(7.2	)		(3.9	)
	Non-controlling interest in consolidated partnerships		(1.1	)		(1.3	)
	True-up of prior year depletion in excess of basis		(4.2	)		(5.7	)
	Rate changes of prior year deferreds		0.4			3.9
	Increase in valuation allowance and other		(21.3	)		(31.7	)

	Total income tax expense		5	%		0	%


Summary of deferred tax assets and liabilities	(in thousands)	December 31, 2014			December 31, 2013

	Deferred tax assets
	Net operating loss carryforwards	$	2,622		$	6,754
	Depletion carryforwards		2,347			1,435
	Accrual and other		1,242			1,043
	Derivatives		(496	)		125
	Asset retirement obligations		1,118			1,024
	Property, plant and equipment		7,011			5,009
	Total deferred tax assets		13,844			15,390

	Deferred tax liability
	Interest in partnerships		(628	)		(475	)

	Less valuation allowance		(13,216	)		(14,915	)

	Net deferred tax asset	$	-		$	-

Stockholders_Equity_Tables

Stockholders' Equity (Tables)	12 Months Ended
Stockholders' Equity (Tables)	Dec. 31, 2014
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, 2013		163,076		$	0.61		3

	Outstanding – December 31, 2013		163,076			0.61		2

	Outstanding – December 31, 2014		163,076			0.61		1

	Exercisable – December 31, 2014		163,076		$	0.61		1



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, 2013		1,166,160

	Granted		1,920,000

	Restricted performance units, non-vested, December 31, 2013		3,086,160

	Granted		1,600,000

	Restricted performance units, non-vested, December 31, 2014		4,686,160



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, 2013		1,610,000		$	0.62

	Granted		1,600,000			0.64

	Vested		(429,997	)		0.62

	Restricted stock awards, nonvested, December 31, 2013		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

Accounts_Payable_and_Accrued_L1

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
Accounts Payable and Accrued Liabilities (Tables)	Dec. 31, 2014
Accounts Payable and Accrued Liabilities [Abstract]
Summary of accounts payable and accrued liabilities		As of December 31,
	(in thousands)	2014		2013

	Accounts payable	$	742	$	2,151
	Oil and gas revenue payable to oil and gas property owners		1,296		1,307
	Production taxes payable		132		165
	Drilling advances received from joint venture partner		2,354		740
	Accrued drilling costs		166		162
	Accrued lease operating costs		74		42
	Accrued ad valorem taxes		1,194		681
	Accrued general and administrative expenses		1,247		1,146
	Accrued income taxes payable		377		-
	Other liabilities		210		211

	Total accounts payable and accrued liabilities	$	7,792	$	6,605

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2014
Fair Value Measurements [Abstract]
Summary of financial assets and liabilities at fair value
		Fair Value Measurements Using
	(in thousands)	Level 1		Level 2		Level 3		Total
	31-Dec-14
	Assets:
	Commodity derivatives	$	-	$	1,322	$	-	$	1,322

	31-Dec-13
	Liabilities:
	Commodity derivatives	$	-	$	326	$	-	$	326

Physical_Delivery_Contracts_an1

Physical Delivery Contracts and Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
Physical Delivery Contracts and Commodity Derivatives [Abstract]
Schedule of swap agreements			Natural Gas								Oil
							Weighted								Weighted
							Average								Average
	Period		MMBtu				Price (a)				Bbl				Price (b)
	Jan - Mar 2015			220,000			$	4.06				5,000			$	94.52
	Apr - Jun 2015			170,000			$	4.04				3,000			$	94.8
	Jul - Sep 2015			180,000			$	4.05				2,000			$	94.8
	Oct - Dec 2015			180,000			$	4.05				-				-
	Jan - Mar 2016			30,000			$	4.2				-				-
	Apr-16			10,000			$	4.2				-				-



	(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.
Schedule of fair value of the derivatives recorded	(in thousands)		As of December 31,
			2014				2013
	Commodity derivative contracts:
	Current assets		$	1,322			$	-
	Current liabilities		$	-			$	226
	Non-current liabilities		$	-			$	100
Schedule of realized and unrealized gains and losses	(in thousands)		For the year ended
	(in thousands)		December 31,
			2014				2013
	Commodity derivative contracts:
	Realized (losses)		$	(402	)		$	(220	)
	Unrealized gains (losses)			1,648				(239	)

	Total realized and unrealized gains (losses), net		$	1,246			$	(459	)
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 derivative asset		$	1,322			$	-			$	1,322

	Total derivative assets				$	1,322			$	-			$	1,322

Commitments_Tables

Commitments (Tables)	12 Months Ended
Commitments (Tables)	Dec. 31, 2014
Commitments [Abstract]
Summary of firm transportation volumes and related demand charges
	Period	Dekatherms per day		Demand Charges
	Jan 2015 - May 2015		5,950	$0.20 - $0.67
	Jun 2015 - Oct 2015		4,800	$0.22 - $0.67
	Nov 2015 - Dec 2017		3,300	$0.22 - $0.67
	Jan 2018 - May 2036		1,000	$0.22

Supplemental_Cash_Flow_Disclos1

Supplemental Cash Flow Disclosures (Tables)	12 Months Ended
Supplemental Cash Flow Disclosures (Tables)	Dec. 31, 2014
Supplemental Cash Flow Disclosures [Abstract]
Supplemental cash flow disclosures	(in thousands)	For the Year Ended
	(in thousands)	December 31,
		2014			2013

	Cash paid for interest payments	$	482		$	548

	Non-cash transactions:
	Increase (decrease) in net asset retirement obligations	$	152		$	240
	(Decrease) increase in accounts payable and accrued liabilities included in oil and gas properties	$	(932	)	$	1,046
	Receivables due from partners assumed in acquisitions	$	2		$	20

Supplemental_Financial_Data_Oi1

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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		2014									2013
		Oil			Natural Gas			Total			Oil			Natural Gas			Total
		MBbls			MMcf			MMcfe			MBbls			MMcf			MMcfe

	Proved reserves, beginning of year		822			36,684			41,616			872			33,646			38,878
	Revisions of previous estimates		(40	)		2,358			2,118			(249	)		3,459			1,965
	Extensions and discoveries		205			44			1,274			305			1,394			3,224
	Production		(134	)		(2,138	)		(2,942	)		(107	)		(2,252	)		(2,894	)
	Purchases of reserves in-place		-			-			-			1			437			443
	Sales of reserves in-place		-			-			-			-			-			-
	Proved reserves, end of year		853			36,948			42,066			822			36,684			41,616

	Proved developed reserves at:
	End of Year		770			35,935			40,555			748			35,317			39,805
	Proved undeveloped reserves at:
	End of Year		83			1,013			1,511			74			1,367			1,811
Summary of aggregate capitalized costs relating to oil and gas producing activities		2014			2013
		(in thousands)
	Oil and gas properties
	Proved oil and gas properties	$	95,233		$	100,769
	Unproved properties not subject to depletion		2,789			2,235
	Accumulated depreciation, depletion, amortization and impairment		(64,535	)		(61,736	)
	Net oil and gas properties	$	33,487		$	41,268
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities		2014			2013
		(in thousands)
	Property acquisition costs:
	Unevaluated properties	$	2,165		$	1,117
	Proved properties and gathering facilities		78			501
	Development costs		8,685			7,818
	Gathering facilities		144			1
	Asset retirement obligation		152			240
	Total costs incurred	$	11,224		$	9,677
Summary of company's investment in unproved properties		2014			2013			2012 and Prior
		(in thousands)

	Acquisition costs	$	1,762		$	832		$	195
Summary of results of operations from oil and gas producing activities		2014			2013
		(in thousands)

	Oil and gas sales, including commodity derivative gains	$	23,789		$	18,222
	Expenses:
	Production expenses		6,797			5,487
	Depletion expense		2,800			2,789
	Accretion of asset retirement obligations		117			138
	Total expenses		9,714			8,414
	Results of operations from oil and gas producing activities	$	14,075		$	9,808

	Depletion rate per Mcfe	$	0.95		$	0.96
Summary of estimate of the current market value of the Company's proved reserves		December 31,
		2014			2013
		(in thousands)

	Future cash inflows	$	250,659		$	218,545
	Future production costs		(96,035	)		(91,013	)
	Future development costs		(3,908	)		(4,152	)
	Future income taxes		(32,234	)		(13,920	)
	Future net cash flows		118,482			109,460
	10% annual discount		(53,476	)		(53,018	)
	Standardized measure of discounted future net cash flows	$	65,006		$	56,442
Summary of discounted future cash flows relating to proved oil and gas reserves		December 31,
		2014			2013
		(in thousands)

	Standardized measure of discounted future net cash flows, beginning of year	$	56,442		$	45,592
	Sales of oil and gas, net of production costs and taxes		(15,746	)		(13,194	)
	Price revisions		10,220			2,852
	Extensions, discoveries and improved recovery, less related costs		6,561			10,869
	Changes in estimated future development costs		959			980
	Development costs incurred during the period		1,010			782
	Quantity revisions		3,490			2,513
	Accretion of discount		5,644			4,559
	Net changes in future income taxes		(2,010	)		-
	Purchases of reserves-in-place		-			293
	Sales of reserves-in-place		-			-
	Changes in production rates timing and other		(1,564	)		1,196
	Standardized measure of discounted future net cash flows, end of year	$	65,006		$	56,442
Summary of weighted averaged adjusted prices		2014			2013
	Oil (per Bbl)	$	92.1		$	94.08
	Natural Gas (per Mcf)	$	4.64		$	3.84

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Dec. 31, 2014	Dec. 31, 2013
Purchaser A [Member]
Concentration Risk [Line Items]
Percentages by purchaser	29.00%	11.00%
Purchaser B [Member]
Concentration Risk [Line Items]
Percentages by purchaser	20.00%	1.00%
Purchaser C [Member]
Concentration Risk [Line Items]
Percentages by purchaser	13.00%	22.00%
Purchaser D [Member]
Concentration Risk [Line Items]
Percentages by purchaser	11.00%	4.00%
Purchaser E [Member]
Concentration Risk [Line Items]
Percentages by purchaser	7.00%	39.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary of reconciliation of the ARO
Balance at beginning of year	$2,699	$2,321
Accretion expense	117	138
Additions during period	152	123
Additions assumed with acquired properties		117
Costs incurred
Balance at end of year	$2,968	$2,699

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Details Textual) (USD $)	12 Months Ended
Share data in Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	Partnership	Dec. 31, 2013
Summary of Significant Accounting Policies (Textual)
Purchaser imbalance liability	$182,000
Number of consolidated partnerships	46
Gas to oil conversion ratio (thousand cubic feet of natural gas per barrel of oil)	6
Percentage of discount factor applied to estimated future net revenues from proved oil and gas reserves	10.00%
Property, plant and equipment, estimated useful lives	Three to seven years
Cost method investments, additional information	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.
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.
Anti-dilutive common stock equivalents which are excluded from the calculation of diluted loss per share	2.7	2.7
Restricted Performance Units [Member]
Summary of Significant Accounting Policies (Textual)
Common stock equivalent restricted to future contingencies	4.7	3.2
Minimum [Member]
Summary of Significant Accounting Policies (Textual)
Percentages by purchaser	10.00%	10.00%
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) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Feb. 25, 2014	31-May-13
	Dec. 31, 2014	Well	31-May-13
Dispositions and Acquisitions (Textual)
Purchase price of natural oil properties			$517,000
Description of defects	Less than the twenty percent (20%) .
Nytis LLC [Member]
Dispositions and Acquisitions (Textual)
Cash transferred	12,400,000
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		20
Purchase price of natural oil properties		$1,100,000

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil and gas properties
Accumulated depreciation, depletion, amortization and impairment	($64,535)	($61,736)
Net oil and gas properties	33,487	41,268
Furniture and fixtures, computer hardware and software, and other equipment	1,131	960
Accumulated depreciation and amortization	-827	-673
Net other property and equipment	304	287
Total net property and equipment	33,791	41,555
Proved oil and gas properties [Member]
Oil and gas properties
Oil and gas properties, gross	95,233	100,769
Unproved properties not subject to depletion [Member]
Oil and gas properties
Oil and gas properties, gross	$2,789	$2,235

Property_and_Equipment_Details1

Property and Equipment (Details 1) (Unproved properties not subject to depletion [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Oil and gas properties, gross	$2,789	$2,235
Indiana [Member]
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Oil and gas properties, gross	433	446
Illinois [Member]
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Oil and gas properties, gross	420	354
Kentucky [Member]
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Oil and gas properties, gross	1,142	1,367
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	$728	$2

Property_and_Equipment_Details2

Property and Equipment (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Per_Mcfe	Per_Mcfe
Property and Equipment (Textual)
Period of amortization of capital costs	5 years
Capitalized overhead applicable to acquisition, development and exploration activities	$520,000	$483,000
Depletion expense related to oil and gas properties	2,800,000	2,200,000
Depletion expense related to oil and gas properties (in dollars per Mcfe)	0.95	0.96
Depreciation and amortization expense	154,000	133,000
Proved property	194,000	4,000
Unproved properties not subject to depletion [Member]
Property and Equipment (Textual)
Oil and gas properties, gross	$2,789,000	$2,235,000

Equity_Method_Investment_Detai

Equity Method Investment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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	$8	($91)

Bank_Credit_Facility_Details

Bank Credit Facility (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
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-17
Maximum borrowing base	50
Outstanding borrowings	2.1
Additional borrowing capacity available	$17.90
Effective borrowing rate (as a percent)	3.00%
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] \| Alternate Base Rate [Member]
Bank Credit Facility (Textual)
Percentage of increased points added to the reference rate	1.50%
Credit facility [Member] \| Alternate Base Rate [Member] \| Minimum [Member]
Bank Credit Facility (Textual)
Percentage of increased points added to the reference rate	4.50%
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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary of provision for income taxes
Current income tax expense	$377
Deferred income tax expense	1,624	1,351
Change in valuation allowance	-1,624	-1,351
Total income tax expense	$377

Income_Taxes_Details_1

Income Taxes (Details 1)	12 Months Ended
Income Taxes (Details 1)	Dec. 31, 2014	Dec. 31, 2013
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	3.40%	3.70%
Percentage depletion in excess of basis	-7.20%	-3.90%
Non-controlling interest in consolidated partnerships	-1.10%	-1.30%
True-up of prior year depletion in excess of basis	-4.20%	-5.70%
Rate changes of prior year deferreds	0.40%	3.90%
Increase in valuation allowance and other	-21.30%	-31.70%
Total income tax expense	5.00%	0.00%

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets
Net operating loss carryforwards	$2,622	$6,754
Depletion carryforwards	2,347	1,435
Accrual and other	1,242	1,043
Derivatives	-496	125
Asset retirement obligations	1,118	1,024
Property, plant and equipment	7,011	5,009
Total deferred tax assets	13,844	15,390
Deferred tax liability
Interest in partnerships	-628	-475
Less valuation allowance	-13,216	-14,915
Net deferred tax asset

Income_Taxes_Details_Textual

Income Taxes (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Income Taxes (Textual)
Net operating losses	$6.30
Operating loss expiration year	31-Dec-33
Net operating losses carryforward	$10

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)	12 Months Ended
Stockholders' Equity (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of number of shares and exercise price of options outstanding and exercisable
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	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	$0.61	$0.61
Weighted Average Remaining Contractual Life (Years) Options Outstanding	1 year	2 years	3 years
Weighted Average Remaining Contractual Life (Years) Options Exercisable	1 year

Stockholders_Equity_Details_1

Stockholders' Equity (Details 1) (USD $)	12 Months Ended
Stockholders' Equity (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Restricted Performance Units [Member]
Summary of Company's unvested restricted stock
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	3,086,160	1,166,160
Granted, Number of Shares	1,600,000	1,920,000
Restricted stock awards, nonvested, Ending Balance, Number of Shares	4,686,160	3,086,160
Carbon 2011 Stock Incentive Plan [Member]
Summary of Company's unvested restricted stock
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	2,780,003	1,610,000
Granted, Number of Shares	1,600,000	1,600,000
Vested, Number of Shares	-856,662	-429,997
Restricted stock awards, nonvested, Ending Balance, Number of Shares	3,523,341	2,780,003
Restricted stock awards, nonvested, Beginning Balance, Weighted Avg Grant Due Fair Value	0.63	0.62
Granted, Weighted Avg Grant Due Fair Value	0.59	0.64
Vested, Weighted Avg Grant Due Fair Value	0.63	0.62
Restricted stock awards, nonvested, Ending Balance, Weighted Avg Grant Due Fair Value	0.61	0.63

Stockholders_Equity_Details_Te

Stockholders' Equity (Details Textual) (USD $)	12 Months Ended			0 Months Ended	12 Months Ended
Stockholders' Equity (Details Textual) (USD $)	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Jun. 25, 2013	Dec. 31, 2010	Dec. 31, 2005	Dec. 31, 2011
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	106,875,447		114,470,223
Common stock, shares outstanding	106,875,447		114,470,223
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
Percentage of shareholder's holdings of the company's common stock	50.00%
Number of shares outstanding	163,076	163,076	163,076
Number of Shares Exercisable	163,076		163,076
Grant date fair value	$0.59	$0.64
Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Compensation costs for restricted stock grants	$346,000		$218,000
Unrecognized compensation cost	473,000
Expected period of recognition of unrecognized compensation costs	1 year 3 months 18 days
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
Common Stock Purchase Agreement [Member]
Stockholders' Equity (Textual)
Repurchase of company's common stock from a shareholder	8,200,000
Percentage of shareholder's holdings of the company's common stock	100.00%
Common stock repurchase price per share	400
Equity Plans Prior To Merger [Member] \| Stock Options [Member]
Stockholders' Equity (Textual)
Number of shares outstanding	163,076
Number of Shares Exercisable	163,076
Equity Plans Prior To Merger [Member] \| Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		2,696,133	2,696,133
Equity Plans Prior To Merger [Member] \| Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares outstanding	1,468,181	1,956,912	1,956,907
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.
Compensation costs for restricted stock grants	335,000		168,000
Unrecognized compensation cost	671,000
Expected period of recognition of unrecognized compensation costs	2 years
Vesting, percentage				25.00%
Carbon 2011 Stock Incentive Plan [Member] \| Officer [Member]
Stockholders' Equity (Textual)
Stock incentive plan, common stock shares authorized							12,600,000
Nytis USA [Member] \| Warrant [Member]
Stockholders' Equity (Textual)
Number of shares outstanding	2,696,133
Number of warrants granted by SLSC	250,000
Number of warrants granted in period						2,446,133
Exercise price	$1				$0.85	$0.61
Expiration date	31-Aug-17					1-Jun-15
Increasing percentage of exercise price						6.00%
Number of shares issuable upon conversion of each option						1
Nytis USA [Member] \| Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Number of shares outstanding			1,956,907				1,956,912
Carbon Natural Gas Company [Member] \| Restricted Stock Units (RSUs) [Member]
Stockholders' Equity (Textual)
Unrecognized compensation cost	1,300,000
Compensation cost recognized	811,000		526,000
Expected period of recognition of unrecognized compensation costs	6 years 3 months 18 days
Carbon Natural Gas Company [Member] \| Restricted Stock Units (RSUs) [Member] \| Employee [Member]
Stockholders' Equity (Textual)
Expected period of recognition of unrecognized compensation costs			3 years
Carbon Natural Gas Company [Member] \| Restricted Stock Units (RSUs) [Member] \| Non Employee [Member]
Stockholders' Equity (Textual)
Expected period of recognition of unrecognized compensation costs			3 years
Carbon Natural Gas Company [Member] \| Restricted Performance Units [Member]
Stockholders' Equity (Textual)
Number of shares outstanding		1,096,500
Unrecognized compensation cost	$2,200,000	$2,200,000

Accounts_Payable_and_Accrued_L2

Accounts Payable and Accrued Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary of accounts payable and accrued liabilities
Accounts payable	$742	$2,151
Oil and gas revenue payable to oil and gas property owners	1,296	1,307
Production taxes payable	132	165
Drilling advances received from joint venture partner	2,354	740
Accrued drilling costs	166	162
Accrued lease operating costs	74	42
Accrued ad valorem taxes	1,194	681
Accrued general and administrative expenses	1,247	1,146
Accrued income taxes payable	377
Other liabilities	210	211
Total accounts payable and accrued liabilities	$7,792	$6,605

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Liabilities:
Commodity derivatives		$226
Recurring basis [Member]
Liabilities:
Commodity derivatives	1,322	326
Recurring basis [Member] \| Level 1 [Member]
Liabilities:
Commodity derivatives
Recurring basis [Member] \| Level 2 [Member]
Liabilities:
Commodity derivatives	1,322	326
Recurring basis [Member] \| Level 3 [Member]
Liabilities:
Commodity derivatives

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Agreements	Agreements
Fair Value Measurements (Textual)
Asset retirement obligations	152,000	240,000
Swap [Member] \| Oil [Member]
Fair Value Measurements (Textual)
Number of agreements	2	5
Swap [Member] \| Natural Gas [Member]
Fair Value Measurements (Textual)
Number of agreements	7	9

Physical_Delivery_Contracts_an2

Physical Delivery Contracts and Commodity Derivatives (Details) (Swap [Member])	Dec. 31, 2014
Jan - Mar 2015 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	220,000
Weighted Average Price	4.06	[1]
Jan - Mar 2015 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity	5,000
Weighted Average Price	94.52	[2]
Apr - Jun 2015 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	170,000
Weighted Average Price	4.04	[1]
Apr - Jun 2015 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity	3,000
Weighted Average Price	94.8	[2]
Jul - Sep 2015 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	180,000
Weighted Average Price	4.05	[1]
Jul - Sep 2015 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity	2,000
Weighted Average Price	94.8	[2]
Oct - Dec 2015 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	180,000
Weighted Average Price	4.05	[1]
Oct - Dec 2015 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity
Weighted Average Price		[2]
Jan - Mar 2016 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	30,000
Weighted Average Price	4.2	[1]
Jan - Mar 2016 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity
Weighted Average Price		[2]
Apr 2016 [Member] \| Natural Gas [Member] \| NYMEX Henry Hub Natural Gas Futures Contract [Member]
Summary of swap agreements
Quantity	10,000
Weighted Average Price	4.2	[1]
Apr 2016 [Member] \| Oil [Member] \| NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]
Summary of swap agreements
Quantity
Weighted Average Price		[2]

[1]	(a) NYMEX Henry Hub Natural Gas futures contract for the respective delivery month.
[2]	(b) NYMEX Light Sweet Crude West Texas Intermediate futures contract for the respective delivery month.

Physical_Delivery_Contracts_an3

Physical Delivery Contracts and Commodity Derivatives (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity derivative contracts:
Current assets	$1,322
Current liabilities		226
Non-current liabilities		$100

Physical_Delivery_Contracts_an4

Physical Delivery Contracts and Commodity Derivatives (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity derivative contracts:
Unrealized gains (losses)	$1,648	($239)
Commodity derivative contracts [Member]
Commodity derivative contracts:
Realized (losses)	-402	-220
Unrealized gains (losses)	1,648	-239
Total realized and unrealized (losses) gains, net	$1,246	($459)

Physical_Delivery_Contracts_an5

Physical Delivery Contracts and Commodity Derivatives (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity derivative assets:
Current derivative asset	$1,322
Total derivative assets	1,322
Gross Recognized Assets/Liabilities [Member]
Commodity derivative assets:
Current derivative asset	1,322
Total derivative assets	1,322
Gross Amounts Offset [Member]
Commodity derivative assets:
Current derivative asset
Total derivative assets
Net Recognized Fair Value Assets/Liabilities [Member]
Commodity derivative assets:
Current derivative asset	1,322
Total derivative assets	$1,322

Physical_Delivery_Contracts_an6

Physical Delivery Contracts and Commodity Derivatives (Details Textual) (Natural Gas [Member], January 2015 through August 2015 [Member])	12 Months Ended
	Dec. 31, 2014
Natural Gas [Member] \| January 2015 through August 2015 [Member]
Physical Delivery Contracts and Commodity Derivatives (Textual)
Physical deliveries required for fixed price contracts (in Bbl per month)	530
Average sales price (in dollars per Bbl)	96.75

Commitments_Details

Commitments (Details) (Long-term transportation contracts [Member])	12 Months Ended
	Dec. 31, 2014
	Dekatherm
Jan 2015 - May 2015 [Member]
Supply Commitment [Line Items]
Capacity levels (Dekatherms per day)	5,950
Jun 2015 - Oct 2015 [Member]
Supply Commitment [Line Items]
Capacity levels (Dekatherms per day)	4,800
Nov 2015 - Dec 2017 [Member]
Supply Commitment [Line Items]
Capacity levels (Dekatherms per day)	3,300
Jan 2018 - May 2036 [Member]
Supply Commitment [Line Items]
Capacity levels (Dekatherms per day)	1,000
Demand charges (in dollars per dekatherm)	0.22
Maximum [Member] \| Jan 2015 - May 2015 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.67
Maximum [Member] \| Jun 2015 - Oct 2015 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.67
Maximum [Member] \| Nov 2015 - Dec 2017 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.67
Minimum [Member] \| Jan 2015 - May 2015 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.2
Minimum [Member] \| Jun 2015 - Oct 2015 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.22
Minimum [Member] \| Nov 2015 - Dec 2017 [Member]
Supply Commitment [Line Items]
Demand charges (in dollars per dekatherm)	0.22

Commitments_Details_Textual

Commitments (Details Textual) (USD $)	12 Months Ended
Commitments (Details Textual) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Commitments (Textual)
Rental expenses incurred	$207,000	$189,000
Office space [Member] \| Denver [Member]
Commitments (Textual)
Area of land	5,500
Lease expiration date	31-Dec-16
Office space [Member] \| Lexington [Member]
Commitments (Textual)
Area of land	5,300
Office space and equipment [Member]
Commitments (Textual)
Minimum lease payments for 2015	238,000
Minimum lease payments for 2016	171,000
Long-term transportation contracts [Member]
Commitments (Textual)
Description of agreements term	The term of the agreements generally range from one to two years and provide for renewal provisions in one year increments thereafter.
Liability related to firm transportation contracts assumed	$1,300,000

Retirement_Savings_Plan_Detail

Retirement Savings Plan (Details) (USD $)	12 Months Ended
Retirement Savings Plan (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Retirement Savings Plan (Textual)
Matching percentage under retirement savings plan	6.00%
401(K) contributions and related administrative expenses	$249,000	$192,000

Supplemental_Cash_Flow_Disclos2

Supplemental Cash Flow Disclosures (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Cash paid during the period for:
Cash paid for interest payments	$482	$548
Non-cash transactions:
Increase (decrease) in net asset retirement obligations	152	240
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	-932	1,046
Receivables due from partners assumed in acquisitions	$2	$20

Subsequent_Events_Details

Subsequent Events (Details)	12 Months Ended
Subsequent Events (Details)	Dec. 31, 2014
Subsequent Events [Abstract]
Product Liability Contingency, Description	Less than the twenty percent (20%) .

Supplemental_Financial_Data_Oi2

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	MMcf	MMcf
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	41,616	38,878
Revisions of previous estimates	2,118	1,965
Extensions and discoveries	1,274	3,224
Production	-2,942	-2,894
Purchases of reserves in-place		443
Sales of reserves in-place
Proved reserves, end of year	42,066	41,616
Proved developed reserves at:
End of year	40,555	39,805
Proved undeveloped reserves at:
End of year	1,511	1,811
Oil [Member]
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells
Proved reserves, beginning of year	822	872
Revisions of previous estimates	-40	-249
Extensions and discoveries	205	305
Production	-134	-107
Purchases of reserves in-place		1
Sales of reserves in-place
Proved reserves, end of year	853	822
Proved developed reserves at:
End of year	770	748
Proved undeveloped reserves at:
End of year	83	74
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	36,684	33,646
Revisions of previous estimates	2,358	3,459
Extensions and discoveries	44	1,394
Production	-2,138	-2,252
Purchases of reserves in-place		437
Sales of reserves in-place
Proved reserves, end of year	36,948	36,684
Proved developed reserves at:
End of year	35,935	35,317
Proved undeveloped reserves at:
End of year	1,013	1,367

Supplemental_Financial_Data_Oi3

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Oil and gas properties
Proved oil and gas properties	$95,233	$100,769
Unproved properties not subject to depletion	2,789	2,235
Accumulated depreciation, depletion, amortization and impairment	-64,535	-61,736
Net oil and gas properties	$33,487	$41,268

Supplemental_Financial_Data_Oi4

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property acquisition costs:
Unevaluated properties	$2,165	$1,117
Proved and unproved properties and gathering facilities	78	501
Development costs	8,685	7,818
Gathering facilities	144	1
Asset retirement obligation	152	240
Total costs incurred	$11,224	$9,677

Supplemental_Financial_Data_Oi5

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of company's investment in unproved properties
Acquisition costs	$1,762	$832	$195

Supplemental_Financial_Data_Oi6

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	Mcf	Mcf
Summary of results of operations from oil and gas producing activities
Oil and gas sales, including commodity derivative gains Expenses:	$23,789	$18,222
Production expenses	6,797	5,487
Depletion expense	2,800	2,789
Accretion of asset retirement obligations	117	138
Total expenses	9,714	8,414
Results of operations from oil and gas producing activities	$14,075	$9,808
Depletion rate per Mcfe	0.95	0.96

Supplemental_Financial_Data_Oi7

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of estimate of the current market value of the Company's proved reserves
Future cash inflows	$250,659	$218,545
Future production costs	-96,035	-91,013
Future development costs	-3,908	-4,152
Future income taxes	-32,234	-13,920
Future net cash flows	118,482	109,460
10% annual discount	-53,476	-53,018
Standardized measure of discounted future net cash flows	$65,006	$56,442	$45,592

Supplemental_Financial_Data_Oi8

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary of discounted future cash flows relating to proved oil and gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$56,442	$45,592
Sales of oil and gas, net of production costs and taxes	-15,746	-13,194
Price revisions	10,220	2,852
Extensions, discoveries and improved recovery, less related costs	6,561	10,869
Changes in estimated future development costs	959	980
Development costs incurred during the period	1,010	782
Quantity revisions	3,490	2,513
Accretion of discount	5,644	4,559
Net changes in future income taxes	-2,010
Purchases of reserves-in-place		293
Sales of reserves-in-place
Changes in production rates timing and other	-1,564	1,196
Standardized measure of discounted future net cash flows, end of year	$65,006	$56,442

Supplemental_Financial_Data_Oi9

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Oil (per Bbl) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices	92.1	94.08
Natural Gas (per Mcf) [Member]
Summary of weighted averaged adjusted prices
Weighted averaged adjusted prices	4.64	3.84

Recovered_Sheet1

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Dec. 31, 2014	MMBbls
Supplemental Financial Data Oil and Gas Producing Activities (Textual)
Estimated proved reserves	3.3 Bcfe	3.3 Bcfe
Decrease of previous oil estimates associated with performance declines		109
Decrease of previous oil estimates associated with offset		161
Discount rate, description	All cash flow amounts, including income taxes, are discounted at 10%.