Carbon Energy (CRBO) 10-K 31 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Mar. 05, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'Carbon Natural Gas Co	'	'
Entity Central Index Key	'0000086264	'	'
Amendment Flag	'false	'	'
Current Fiscal Year End Date	'--12-31	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Period Focus	'FY	'	'
Document Fiscal Year Focus	'2013	'	'
Entity Well-Known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Public Float	'	'	$23.40
Entity Common Stock, Shares Outstanding	'	114,470,223	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$243	$328
Accounts receivable:	'	'
Revenue	2,551	2,665
Joint interest billings and other	416	344
Firm transportation contract obligations (note 12)	211	836
Due from related parties (note 14)	'	446
Prepaid expense, deposits and other current assets	95	114
Total current assets	3,516	4,733
Property and equipment, at cost (note 4)	'	'
Proved, net	39,033	32,186
Unevaluated	2,235	1,126
Other property and equipment, net	287	242
Total property and equipment	41,555	33,554
Investments in affiliates (note 5)	1,002	1,217
Other long-term assets	688	874
Total assets	46,761	40,378
Current liabilities:	'	'
Accounts payable and accrued liabilities	6,605	5,404
Firm transportation contract obligations (note 12)	556	2,200
Derivative liability	226	87
Total current liabilities	7,387	7,691
Non-current liabilities:	'	'
Derivative liability	100	'
Firm transportation contract obligations (note 12)	1,340	1,896
Asset retirement obligations (note 2)	2,699	2,321
Notes payable (note 6)	12,789	11,088
Total non-current liabilities	16,928	15,305
Commitments (note 12)	'	'
Stockholders' equity:	'	'
Preferred stock, $0.01 par value; authorized 1,000,000 shares, no shares issued and outstanding at December 31, 2013 and 2012	'	'
Common stock, $0.01 par value; authorized 200,000,000 shares, 114,470,223 and 115,795,405 shares issued and outstanding at December 31, 2013 and 2012, respectively	1,145	1,158
Additional paid-in capital	55,029	54,195
Non-controlling interests	3,045	3,088
Accumulated deficit	-36,773	-41,059
Total stockholders' equity	22,446	17,382
Total liabilities and stockholders' equity	$46,761	$40,378

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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	114,470,223	115,795,405
Common stock, shares outstanding	114,470,223	115,795,405

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenue:	'	'
Oil and gas	$18,681	$11,750
Commodity derivative (loss) gain	-459	59
Other income	416	267
Total revenue	18,638	12,076
Expenses:	'	'
Lease operating expenses	2,620	2,188
Transportation costs	1,609	1,720
Production and property taxes	1,258	1,370
General and administrative	5,151	4,701
Depreciation, depletion and amortization	2,922	3,136
Accretion of asset retirement obligations	138	105
Impairment of oil and gas properties	'	15,407
Total expenses	13,698	28,627
Operating income (loss)	4,940	-16,551
Other income and (expense):	'	'
Interest expense	-581	-621
Other expenses	'	-316
Equity investment (loss) income	-91	4
Total other (expense) and income	-672	-933
Income (loss) before income taxes	4,268	-17,484
Income taxes:	'	'
Provision for income taxes expense	'	'
Net income (loss)	4,268	-17,484
Net loss attributable to non-controlling interests	18	1,731
Net income (loss) attributable to controlling interest	$4,286	($15,753)
Net income (loss) per common share:	'	'
Basic	$0.04	($0.14)
Diluted	$0.04	($0.14)
Weighted average common shares outstanding (in thousands):	'	'
Basic	112,479	112,228
Diluted	117,096	112,228

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-in Capital	Non-Controlling Interests	Treasury Stock	Accumulated Deficit
In Thousands, except Share data, unless otherwise specified
Beginning Balances at Dec. 31, 2011	$34,642	$1,142	$53,922	$4,884	'	($25,306)
Beginning Balances, (in shares) at Dec. 31, 2011	'	114,185	'	'	'	'
Stock-based compensation	300	'	300	'	'	'
Restricted stock	'	16	-16	'	'	'
Restricted stock (in shares)	'	1,610	'	'	'	'
Other	-11	'	-11	'	'	'
Non-controlling interest:	'	'	'	'	'	'
Distributions, net	-65	'	'	-65	'	'
Net income (loss)	-17,484	'	'	-1,731	'	-15,753
Ending Balances at Dec. 31, 2012	17,382	1,158	54,195	3,088	'	-41,059
Ending Balances, (in shares) at Dec. 31, 2012	'	115,795	'	'	'	'
Stock-based compensation	913	'	913	'	'	'
Restricted stock	-92	-13	-79	'	'	'
Restricted stock (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	'	'	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:	'	'
Net income (loss)	$4,268	($17,484)
Items not involving cash:	'	'
Depreciation, depletion and amortization	2,922	3,136
Accretion of asset retirement obligations	138	105
Impairment of oil and gas properties	'	15,407
Unrealized derivative loss	239	395
Stock-based compensation expense	913	300
Equity investment loss (income)	91	-4
Net change in:	'	'
Accounts receivable	857	572
Prepaid expenses, deposits and other current assets	20	-31
Accounts payable, accrued liabilities and firm transportation contracts	-2,046	-1,368
Due (to)/from related parties	446	-252
Net cash provided by operating activities	7,848	776
Cash flows from investing activities:	'	'
Development of properties and equipment	-9,114	-6,525
Cash paid for acquired properties	-501	-378
Proceeds from disposition of assets	'	3,656
Equity method investment	125	-88
Other long-term assets	-26	160
Net cash used in investing activities	-9,516	-3,175
Cash flows from financing activities:	'	'
Vested restricted stock exchanged for tax withholding	-92	'
Proceeds from notes payable	2,700	5,730
Payments on notes payable	-1,000	-3,400
Distribution to non-controlling interests	-25	-65
Other	'	-11
Net cash provided by financing activities	1,583	2,254
Net decrease in cash and cash equivalents	-85	-145
Cash and cash equivalents, beginning of period	328	473
Cash and cash equivalents, end of period	$243	$328

Organization

Organization	12 Months Ended
	Dec. 31, 2013
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, 2013
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 combined 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 receivable 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, 2013 and 2012, 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, 2013 and 2012.  There are a number of purchasers in the areas that the Company sells its production to and accordingly, 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	2013			2012
	Purchaser A		39	%		34	%
	Purchaser B		22	%		29	%
	Purchaser C		11	%		-
	Purchaser D		7	%		10	%
	The Company recognizes a receivable or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers.  A purchaser imbalance receivable 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, 2013, the Company has a purchaser imbalance liability of approximately $117,000 which is recognized as a current liability 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 incidental 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 oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas.  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.  All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
	The Company performs a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.  The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation.  The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.  Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs.  Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods.
	For the year ended December 31, 2013, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation.  For the year ended December 31, 2012, the Company recognized a ceiling test impairment of approximately $15.4 million.  Future declines in oil and natural gas prices could result in additional 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 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 asset retirement obligation 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 ARO for the years ended December 31, 2013 and 2012.
		Year Ended December 31,
	(in thousands)	2013			2012
	Balance at beginning of year	$	2,321		$	2,149
	Accretion expense		138			105
	Additions during period		123			75
	Additions assumed with acquired properties		117			-
	Costs incurred		-			(8	)
	Balance at end of year	$	2,699		$	2,321
	Financial Instruments
	The Company’s financial instruments include cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, derivative instruments and its credit facility.  The carrying value of cash and cash equivalents, accounts receivable, 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.
	In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily includes a history of book losses which are driven primarily from ceiling test write-downs, which are not fair value based measurements. Positive evidence considered by management includes current and forecasted book income over a reasonable period of time.
	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 (loss) per common share is computed by dividing the net income (loss) 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 (loss) 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 year ended December 31, 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 and approximately 3.2 million restricted performance units subject to future contingencies. For the year ended December 31, 2012, the Company had approximately 4.7 million common stock equivalents that were excluded from the diluted loss per share as the effect would be anti-dilutive. When a loss exists, as for the year ended December 31, 2012, no potentially dilutive common shares are included in computation of diluted per share amount.
	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
	In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”).  The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions or similar agreements.  ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively.  The Company adopted ASU 2011-11 and ASU 2013-01 effective January 1, 2013, which did not have an impact on the Company’s consolidated statements other than additional disclosures.

Dispositions_and_Acquisitions

Dispositions and Acquisitions	12 Months Ended
	Dec. 31, 2013
Dispositions and Acquisitions [Abstract]	'
Dispositions and Acquisitions	'
	Note 3 – Dispositions and Acquisitions
	Liberty Participation Agreement
	In September 2012, Nytis LLC entered into an initial participation agreement (the “Initial 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 Initial Participation Agreement, Liberty paid Nytis LLC approximately $3.7 million.  Upon receiving this payment, Nytis LLC assigned to Liberty a forty percent (40%) working interest in the covered leases. In addition, Liberty paid a greater percentage of the costs associated with the first 20 wells drilled under the Initial Participation Agreement. As of December 31, 2013, Liberty has fulfilled its obligation under the Initial Participation Agreement and Nytis LLC and Liberty now pay their respective costs on an unpromoted basis.  See Note 16 regarding information on the Second Participation Agreement.
	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 Initial Participation Agreement were recorded as a reduction of the Company’s investment in its 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 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.

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property and Equipment [Abstract]	'
Property and Equipment	'
	Note 4 – Property and Equipment
	Net property and equipment at December 31, 2013 and 2012 consists of the following:
	(in thousands)	As of December 31,
		2013			2012
	Oil and gas properties:
	Proved oil and gas properties	$	100,769		$	91,132
	Unproved properties not subject to depletion		2,235			1,126
	Accumulated depreciation, depletion, amortization and impairment		(61,736	)		(58,946	)
	Net oil and gas properties		41,268			33,312
	Furniture and fixtures, computer hardware and software, and other equipment		960			782
	Accumulated depreciation and amortization		(673	)		(540	)
	Net other property and equipment		287			242
	Total net property and equipment	$	41,555		$	33,554
	The Company had approximately $2.2 million and $1.1 million, at December 31, 2013 and 2012, respectively, of unproved oil and gas properties not subject to depletion.  At December 31, 2013 and 2012, the Company’s unproved properties consist principally of leasehold acquisition costs in the following areas:
		As of December 31,
	(in thousands)	2013			2012
	Illinois Basin:
	Indiana	$	446		$	432
	Illinois		354			314
	Appalachian Basin:
	Kentucky		1,367			314
	Ohio		66			65
	West Virginia		2			1
	Total unproved properties not subject to depletion	$	2,235		$	1,126
	During the years ended December 31, 2013 and 2012, expiring leasehold costs reclassified into proved property were approximately $4,000 and $55,000, 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 $483,000 and $529,000 for the years ended December 31, 2013 and 2012, respectively.
	Depletion expense related to oil and gas properties for the years ended December 31, 2013 and 2012 was approximately $2.8 million, or $0.96 per Mcfe, and $3.0 million, or $1.11 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, 2013 and 2012 was approximately $133,000 and $99,000, respectively.

Equity_Method_Investment

Equity Method Investment	12 Months Ended
	Dec. 31, 2013
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 2013 and 2012, the Company recorded an equity method loss of approximately $91,000 and income of approximately $4,000, respectively, related to this investment.

Bank_Credit_Facility

Bank Credit Facility	12 Months Ended
	Dec. 31, 2013
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, 2013, there were approximately $12.8 million in outstanding borrowings and approximately $7.2 million of additional borrowing capacity available under the credit facility.  The Company’s effective borrowing rate at December 31, 2013 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 minimum current ratio (the ratio of current assets (including borrowing base capacity) to current liabilities as defined) of 1.0 to 1.0 and a maximum funded debt ratio (the ratio of the outstanding balance of all interest bearing indebtedness to the sum of EBITDAX (net income plus interest expense, income taxes, depreciation, depletion, amortization, exploration and impairment expenses and other non-cash charges) for the most recently completed fiscal quarter times four) of 4.25 to 1.0 as of the end of any fiscal quarter.
	The Company is in compliance with all covenants associated with the credit agreement as of December 31, 2013.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Income Taxes	'
	Note 7 – Income Taxes
	The provision for income taxes for the years ended December 31, 2013 and 2012 consists of the following:
	(in thousands)
		Year Ended
		December 31,			December 31,
		2013			2012
	Current income tax (benefit) expense	$	-		$	-
	Deferred income tax (benefit) expense		1,351			(5,647	)
	Change in valuation allowance		(1,351	)		5,647
	Total income tax (benefit) expense	$	-		$	-
	The effective income tax rate for the years ended December 31, 2013 and 2012 differed from the statutory U.S. federal income tax rate as follows:
		Year Ended
		December 31,			December 31,
		2013			2012
	Federal income tax rate		(35.0	)%		(35.0	)%
	State income taxes, net of federal benefit		(3.7	)		(3.6	)
	Percentage depletion in excess of basis		3.9			0.1
	Non-controlling interest in consolidated partnerships		1.3			4.4
	True-up of prior year depletion in excess of basis		5.7			-
	Rate changes of prior year deferreds		(3.9	)		1.8
	Increase in valuation allowance and other		31.7			32.3
	Total income tax (benefit)		0	%		0	%
	The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2013 and 2012 are presented below:
	(in thousands)
		December 31,			December 31,
		2013			2012
	Deferred tax assets:
	Net operating loss carryforwards	$	6,754		$	5,777
	Depletion carryforwards		1,435			1,022
	Accrual and other		1,043			713
	Derivatives		125			33
	Asset retirement obligations		1,024			884
	Property, plant and equipment		5,009			8,083
	Total deferred tax assets		15,390			16,512
	Deferred tax liability:
	Interest in partnerships		(475	)		(279	)
	Less valuation allowance		(14,915	)		(16,233	)
	Net deferred tax asset	$	-		$	-
	The Company has net operating losses (“NOL”) of approximately $17.2 million available to reduce future years’ federal taxable income.  The federal NOL expire in 2032.  The Company has NOL of approximately $18.2 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 deferred tax assets related to the Company’s NOL and other deferred tax assets.

Stockholders_Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity [Abstract]	'
Stockholders' Equity	'
	Note 8 – Stockholders’ Equity
	Authorized and Issued Capital Stock
	As of December 31, 2013, the Company had 200,000,000 shares of common stock, par value of $0.01 per share, authorized, 114,470,223 shares of common stock issued and outstanding and 1.0 million shares of preferred stock, par value of $0.01 per share, authorized of which none were issued and outstanding.  During the year ended December 31, 2013, changes in the Company’s issued and outstanding common stock reflect a reduction of restricted stock whose terms were amended such that they were no longer considered issued and outstanding, partially offset by a net increase for restricted stock that vested and was issued during the period.
	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, 2013, 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 1,956,907 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, 2013 and 2012.  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, 2012		269,075		$	0.63		4.4
	Forfeited		(105,999	)		0.67
	Outstanding – December 31, 2012		163,076			0.61		3
	Outstanding – December 31, 2013		163,076			0.61		2
	Exercisable – December 31, 2013		163,076		$	0.61		2
	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, 2013.  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, 2013, there were 1,956,907 shares of restricted stock issued under the Nytis USA Restricted Stock Plan (“Nytis USA Plan”).  The Company accounted for these grants at their intrinsic value.  Historically, the Company estimated that none of these shares would vest and accordingly, no compensation cost had been recorded through December 31, 2012.
	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 $168,000 for the year ended December 31, 2013.  As of December 31, 2013, there was approximately $1.0 million of unrecognized compensation costs related to these restricted stock grants which the Company expects will be recognized ratably over the next 3.5 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 for the Company or the date their membership on the Board of Directors is terminated other than for cause.  The Company recognizes compensation expense for restricted stock 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).  The following table shows a summary of the Company’s unvested restricted stock under the Carbon Plan as of December 31, 2013 and 2012 as well as activity during the years then ended.
					Weighted Avg
		Number			Grant Due
		of Shares			Fair Value
	Restricted stock awards, nonvested, January 1, 2012		-			N/A
	Granted		1,610,000		$	0.62
	Restricted stock awards, nonvested, December 31, 2012		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
	Compensation costs recognized for these restricted stock grants were approximately $526,000 and $300,000 for the years ended December 31, 2013 and 2012, respectively.  As of December 31, 2013, there was approximately $1.2 million of unrecognized compensation costs related to these restricted stock grants which the Company expects to be recognized over the next 2.3 years.  In addition, during the year ending December 31, 2013, the Company modified certain rights related to these shares that eliminated voting and dividend rights until the shares vest, resulting in unvested shares no longer considered issued and outstanding.
	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, 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, 2013 and 2012 as well as activity during the years then ended.
		Number
		of Shares
	Restricted performance units, non-vested, January 1, 2012		-
	Granted		1,290,000
	Forfeited		(123,840	)
	Restricted performance units, non-vested, December 31, 2012		1,166,160
	Granted		1,920,000
	Restricted performance units, non-vested, December 31, 2013		3,086,160
	The Company accounts for the performance units granted during 2012 at their fair value, revaluated at each reporting period to determine if the performance criteria would be met.  The final measurement of compensation cost will be based on the performance units that ultimately vest and the market price on that date.  At December 31, 2013, the Company estimated that none of the performance units granted in 2012 would vest due to change in control provisions and accordingly, no compensation cost has been recorded.  As of December 31, 2013, if the change in control provisions pursuant to the terms and conditions of the agreements would have been met, the estimated unrecognized compensation cost related to the performance units granted in 2012 would have been approximately $991,000.
	The performance units granted in 2013 contain specific vesting provisions and no change in control provisions.  Due to different vesting requirements compared to the performance units granted in 2012, 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 our defined peer group.  The risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the performance units.  The following table summarizes the assumptions used to estimate the grant date fair value of the performance unit awards granted in 2013.
	Risk-free interest rate		0.39	%
	Company expected volatility		92.92	%
	Expected term	2.87 years
	Dividend yield		-
	The grant date fair value of the performance units granted in 2013 as determined by the valuation model was $0.54 per share.  For the year ended December 31, 2013, compensation costs of approximately $218,000 were recognized for the performance units granted in 2013.  As of December 31, 2013, there was approximately $818,000 of unrecognized compensation costs related to these grants.

Accounts_Payable_and_Accrued_L

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 consist of the following:
	(in thousands)
		As of December 31,
		2013		2012
	Accounts payable	$	2,151	$	790
	Oil and gas revenue payable to oil and gas property owners		1,307		1,886
	Production taxes payable		165		123
	Drilling advances received from joint venture partner		740		537
	Accrued drilling costs		162		75
	Accrued lease operating costs		42		61
	Accrued ad valorem taxes		681		596
	Accrued general and administrative expenses		1,146		1,083
	Accrued other		211		253
	Total accounts payable and accrued liabilities	$	6,605	$	5,404

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 by level within the fair value hierarchy:
	(in thousands)		Fair Value Measurements Using
			Level 1		Level 2		Level 3		Total
	31-Dec-13
	Liabilities:
	Commodity derivatives		$	-	$	326	$	-	$	326
	31-Dec-12
	Liabilities:
	Commodity derivatives		$	-	$	87	$	-	$	87
	As of December 31, 2013, the Company’s commodity derivative financial instruments are comprised of nine natural gas swap agreements and five oil swap agreements.  As of December 31, 2012, the Company’s commodity derivative financial instruments were comprised of two natural gas swap agreements and two 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, 2013 and 2012, the Company recorded asset retirement obligations for additions of approximately $240,000 and $75,000, 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
	Dec. 31, 2013
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, 2013, the Company has a fixed price contract requiring physical deliveries for approximately 250 Mcf/day at an average sales price of $4.13 per Mcf from January 2014 through March 2014.  The Company’s other gas sales contracts approximate index prices.
	The Company’s swap agreements as of December 31, 2013 are summarized in the table below:
		Natural Gas								Oil
						Weighted								Weighted
						Average								Average
	Period	MMBtu				Price (a)				Bbl				Price (b)
	Jan - Mar 2014		210,000			$	4.01				9,000			$	93.24
	Apr - Jun 2014		210,000			$	4.05				9,000			$	93.24
	Jul - Sep 2014		210,000			$	4.05				6,000			$	93.14
	Oct - Dec 2014		190,000			$	4.04				6,000			$	93.14
	Jan - Mar 2015		190,000			$	3.98				-				-
	Apr - Jun 2015		150,000			$	4.02				-				-
	Jul - Sep 2015		150,000			$	4.02				-				-
	Oct - Dec 2015		150,000			$	4.02				-				-
	(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,
		2013				2012
	Commodity derivative contracts:
	Current liabilities	$	326			$	87
	The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2013 and 2012.  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 December 31,
		2013				2012
	Commodity derivative contracts:
	Realized (losses) gains	$	(220	)		$	454
	Unrealized losses		(239	)			(395	)
	Total realized and unrealized (losses) gains, net	$	( 459	)		$	59
	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		$	26			$	(26	)		$	-
		Other long-term assets			3				(3	)			-
	Total derivative assets			$	29			$	(29	)		$	-
	Commodity derivative liabilities:	Current derivative liability			252				(26	)			226
		Long-term derivative liability			103			(3	)			100
	Total derivative liabilities			$	355			$	(29	)		$	326
	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, 2013
Commitments [Abstract]	'
Commitments	'
	Note 12 – Commitments
	The Company has entered into employment agreements with certain executives and officers of the Company.  The initial term of the agreements generally range from one to three 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, 2013 are summarized in the table below.
	Period	Dekatherms per day	Demand Charges
	Jan - Mar 2014	7,250	$0.20 - $0.67
	Apr - Oct 2014	6,450	$0.20 - $0.67
	Nov 2014 - May 2015	4,450	$0.20 - $0.67
	Jun 2015 - Dec 2017	3,300	$0.22 - $0.67
	Jan 2018 - May 2036	1,000	$0.22
	A liability of approximately $1.9 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, 2013.  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, expiring in 2016.  For the years ended December 31, 2013 and 2012, the Company incurred rental expenses of $189,000 and $148,000, respectively.  The Company has minimum lease payments for its office space and equipment of approximately $260,000, $238,000 and $171,000 for 2014, 2015 and 2016, respectively.

Retirement_Savings_Plan

Retirement Savings Plan	12 Months Ended
	Dec. 31, 2013
Retirement Savings Plan [Abstract]	'
Retirement Savings Plan	'
	Note 13 – Retirement Savings Plan
	The Company outsources certain payroll and human resource functions.  In conjunction with these arrangements, 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, 2013 and 2012, the Company paid approximately $192,000 and $168,000, respectively, for 401(k) contributions and related administrative expenses.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Note 14 – Related Party Transactions
	Pursuant to a service agreement entered into in 2011 between the Company and a related entity, the Company managed, directed and supervised the operations and business of the related entity for a monthly fee of $15,000.  Effective June 30, 2012, the agreement was terminated.  For the year ended December 31, 2012, the Company received $90,000 in management fees.

Supplemental_Cash_Flow_Disclos

Supplemental Cash Flow Disclosures	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Disclosures [Abstract]	'
Supplemental Cash Flow Disclosures	'
	Note 15 – Supplemental Cash Flow Disclosures
	Supplemental cash flow disclosures for the years ended December 31, 2013 and 2012 are presented below:
	(in thousands)	For the Year Ended December 31,
		2013		2012
	Cash paid for interest payments	$	548	$	590
	Non-cash transactions:
	Increase (decrease) in net asset retirement obligations	$	240	$	75
	Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	$	1,046	$	1,772
	Receivables due from partners assumed in acquisitions	$	20	$	-

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Note 16 – Subsequent Events
	On February 25, 2014, Nytis LLC entered into a second participation agreement (the “Second Participation Agreement”) with Liberty Energy LLC (“Liberty”), that will allow 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 Second Participation Agreement, Liberty paid Nytis LLC approximately $1.7 million.  Upon receipt of this payment, Nytis LLC assigned to Liberty a forty percent (40%) working interest in the covered leases.  In addition, Liberty will carry a greater percentage of the costs associated with drilling and completing the initial wells on the covered leases.  Nytis LLC has the right to provide additional net mineral acres prior to the later of (a) December 31, 2014 or (b) the date that is nine (9) months after the date that the last well was spud in the covered area and, upon delivery of a maximum amount of additional net mineral acres, Nytis LLC will be entitled to additional payments up to a maximum of $1.1 million.  Liberty has committed to participate on the basis described above in one (1) well per 1,000 net mineral acres associated with the covered leases, up to a maximum of 20 wells.  Following the drilling of these initial wells, the parties will pay their respective costs on an unpromoted basis.
	The Second Participation Agreement also provides for the reservation by Nytis LLC for an overriding royalty interest with respect to covered leases that include an agreed upon minimum net revenue interest.
	Should Liberty decide not to participate in all of the initial wells on the basis described above, it will re-assign the 40% working interest for the properties in which it does not participate and will retain a 40% working interest in the approved spacing units associated with only those wells in which it did so participate.  If Liberty does participate fully in the initial wells then it will have no further re-assignment obligations and will hold its 40% working interest in all of the covered leases and the parties will continue to develop these oil and gas interests on an unpromoted basis pursuant to an industry-standard joint operating agreement.

Supplemental_Financial_Data_Oi

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2013
Supplemental Financial Data - Oil and Gas Producing Activities (Unaudited) [Abstract]	'
Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)	'
	Note 17 – Supplemental Financial Data – Oil and Gas Producing Activities (unaudited)
	Estimated Proved Oil and Gas Reserves
	The reserve estimates as of December 31, 2013 and 2012 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, 2013 and 2012 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 2013 and 2012 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, 2013 and 2012 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, 2013 and 2012.  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, 2013 and 2012.  (See Note 2)
	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, 2013 and 2012 are as follows:
		2013										2012
		Oil				Natural Gas			Total			Oil			Natural Gas			Total
		MBbls				MMcf			MMcfe			MBbls			MMcf			MMcfe
	Proved reserves, beginning of year		872				33,646			38,878			732			62,952			67,344
	Revisions of previous estimates		(249	)			3,459			1,965			(236	)		(27,163	)		(28,579	)
	Extensions and discoveries		305				1,394			3,224			457			274			3,016
	Production		(107	)			(2,252	)		(2,894	)		(52	)		(2,417	)		(2,729	)
	Purchases of reserves in-place		1				437			443			-			-			-
	Sales of reserves in-place		-				-			-			(29	)		-			(174	)
	Proved reserves, end of year		822				36,684			41,616			872			33,646			38,878
	Proved developed reserves at:
	End of year		748				35,317			39,805			489			33,398			36,332
	Proved undeveloped reserves at:
	End of year		74				1,367			1,811			383			248			2,546
	The estimated proved reserves for December 31, 2013 and 2012 includes 3.3 Bcfe in each year attributed to non-controlling interests of consolidated partnerships.
	In 2013 and 2012, revisions of previous oil estimates consisted of a decrease of approximately 109 and 74 MBbls, respectively, associated with performance declines and a decrease of approximately 161 and 163 MBbls, respectively, associated with offset proved undeveloped locations that were determined not to be viable.  Revisions in 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; whereas, in 2012,  revisions of previous estimates for natural gas were primarily attributed to the loss of proved undeveloped locations due to significant decreases in natural gas prices.
	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:
		2013				2012
		(in thousands)
	Oil and gas properties
	Proved oil and gas properties	$	100,769			$	91,132
	Unproved properties not subject to depletion		2,235				1,126
	Accumulated depreciation, depletion, amortization and impairment		(61,736	)			(58,946	)
	Net oil and gas properties	$	41,268			$	33,312
	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, 2013 and 2012:
		2013				2012
		(in thousands)
	Property acquisition costs:
	Unevaluated properties	$	1,117			$	509
	Proved and unproved properties and gathering facilities		501				378
	Development costs		7,818				5,734
	Gathering facilities		1				227
	Asset retirement obligations		240				75
	Total costs incurred	$	9,677			$	6,923
	The Company’s investment in unproved properties as of December 31, 2013, by the year in which such costs were incurred is set forth in the table below:
		2013				2012			2011 and Prior
		(in thousands)
	Acquisition costs	$	1,117			$	509		$	609
	Results of Operations from Oil and Gas Producing Activities
	Results of operations from oil and gas producing activities for the years ended December 31, 2013 and 2012 are presented below:
		2013				2012
		(in thousands)
	Oil and gas sales, including commodity derivative gains	$	18,222			$	11,809
	Expenses:
	Production expenses		5,487				5,278
	Depletion expense		2,789				3,037
	Ceiling test write-down of oil and gas properties		-				15,407
	Accretion of asset retirement obligations		138				105
	Total expenses		8,414				23,827
	Results of operations from oil and gas producing activities	$	9,808			$	(12,018	)
	Depletion rate per Mcfe	$	0.96			$	1.11
	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.  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,
	2013			2012
	(in thousands)
Future cash inflows	$	218,545			$	174,832
Future production costs		(91,013	)			(68,192	)
Future development costs		(4,152	)			(2,813	)
Future income taxes		(13,920	)			(8,078	)
Future net cash flows		109,460				95,749
10% annual discount		(53,018	)			(50,157	)
Standardized measure of discounted future net cash flows	$	56,442			$	45,592
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,
	2013				2012
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	45,592			$	48,889
Sales of oil and gas, net of production costs and taxes		(13,194	)			(6,471	)
Price revisions		2,852				(23,045	)
Extensions, discoveries and improved recovery, less related costs		10,869				13,892
Changes in estimated future development costs		980				30,777
Development costs incurred during the period		782				835
Quantity revisions		2,513				(15,395	)
Accretion of discount		4,559				4,889
Net changes in future income taxes		-				-
Purchases of reserves-in-place		293				-
Sales of reserves-in-place		-				(213	)
Changes in production rates timing and other		1,196				(8,566	)
Standardized measure of discounted future net cash flows, end of year	$	56,442			$	45,592
The twelve month weighted averaged adjusted prices in effect at December 31, 2013 and 2012 were as follows:
	2013				2012
Oil (per Bbl)	$	94.08			$	91.88
Natural Gas (per Mcf)	$	3.84			$	2.8

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
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 combined 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 receivable 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, 2013 and 2012, 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, 2013 and 2012.  There are a number of purchasers in the areas that the Company sells its production to and accordingly, 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	2013			2012
	Purchaser A		39	%		34	%
	Purchaser B		22	%		29	%
	Purchaser C		11	%		-
	Purchaser D		7	%		10	%
	The Company recognizes a receivable or a liability, whichever is appropriate, for revenues associated with over-deliveries or under-deliveries of natural gas to purchasers.  A purchaser imbalance receivable 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, 2013, the Company has a purchaser imbalance liability of approximately $117,000 which is recognized as a current liability 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 incidental 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 oil to gas at the ratio of one barrel of oil to six thousand cubic feet of natural gas. 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.  All costs related to production activities, including work-over costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
	The Company performs a ceiling test quarterly.  The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10.  The ceiling test is not a fair value based measurement. Rather, it is a standardized mathematical calculation.  The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using the un-weighted arithmetic average of the first-day-of-the month price for the previous twelve month period, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.  Should the net capitalized costs exceed the sum of the components noted above, a ceiling test write-down or impairment would be recognized to the extent of the excess capitalized costs.  Such impairments are permanent and cannot be recovered in future periods even if the sum of the components noted above exceeds capitalized costs in future periods.
	For the year ended December 31, 2013, the Company did not recognize a ceiling test impairment as the Company’s full cost pool did not exceed the ceiling limitation.  For the year ended December 31, 2012, the Company recognized a ceiling test impairment of approximately $15.4 million.  Future declines in oil and natural gas prices could result in additional 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 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 asset retirement obligation 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 ARO for the years ended December 31, 2013 and 2012.
		Year Ended December 31,
	(in thousands)	2013			2012
	Balance at beginning of year	$	2,321		$	2,149
	Accretion expense		138			105
	Additions during period		123			75
	Additions assumed with acquired properties		117			-
	Costs incurred		-			(8	)
	Balance at end of year	$	2,699		$	2,321
Financial Instruments	'
	Financial Instruments
	The Company’s financial instruments include cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, derivative instruments and its credit facility.  The carrying value of cash and cash equivalents, accounts receivable, 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.
	In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive. Negative evidence considered by management primarily includes a history of book losses which are driven primarily from ceiling test write-downs, which are not fair value based measurements. Positive evidence considered by management includes current and forecasted book income over a reasonable period of time.
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 (loss) per common share is computed by dividing the net income (loss) 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 (loss) 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 year ended December 31, 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 and approximately 3.2 million restricted performance units subject to future contingencies. For the year ended December 31, 2012, the Company had approximately 4.7 million common stock equivalents that were excluded from the diluted loss per share as the effect would be anti-dilutive. When a loss exists, as for the year ended December 31, 2012, no potentially dilutive common shares are included in the computation of the diluted per share amount.
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
	In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”).  The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position.  In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”), which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with FASB ASC Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities lending transactions or similar agreements.  ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively.  The Company adopted ASU 2011-11 and ASU 2013-01 effective January 1, 2013, which did not have an impact on the Company’s consolidated statements other than additional disclosures.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
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		2013			2012
	Purchaser A			39	%		34	%
	Purchaser B			22	%		29	%
	Purchaser C			11	%		-
	Purchaser D			7	%		10	%
Summary of reconciliation of the ARO	'
		Year Ended December 31,
	(in thousands)		2013			2012
	Balance at beginning of year		$	2,321		$	2,149
	Accretion expense			138			105
	Additions during period			123			75
	Additions assumed with acquired properties			117			-
	Costs incurred			-			(8	)
	Balance at end of year		$	2,699		$	2,321

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property and Equipment [Abstract]	'
Summary of net property and equipment	'
	(in thousands)		As of December 31,
			2013			2012
	Oil and gas properties:
	Proved oil and gas properties		$	100,769		$	91,132
	Unproved properties not subject to depletion			2,235			1,126
	Accumulated depreciation, depletion, amortization and impairment			(61,736	)		(58,946	)
	Net oil and gas properties			41,268			33,312
	Furniture and fixtures, computer hardware and software, and other equipment			960			782
	Accumulated depreciation and amortization			(673	)		(540	)
	Net other property and equipment			287			242
	Total net property and equipment		$	41,555		$	33,554
Summary of unproved oil and gas properties	'
		As of December 31,
	(in thousands)		2013			2012
	Illinois Basin:
	Indiana		$	446		$	432
	Illinois			354			314
	Appalachian Basin:
	Kentucky			1,367			314
	Ohio			66			65
	West Virginia			2			1
	Total unproved properties not subject to depletion		$	2,235		$	1,126

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes [Abstract]	'
Summary of provision for income taxes	'
	(in thousands)
		Year Ended
		December 31,			December 31,
		2013			2012
	Current income tax (benefit) expense	$	-		$	-
	Deferred income tax (benefit) expense		1,351			(5,647	)
	Change in valuation allowance		(1,351	)		5,647
	Total income tax (benefit) expense	$	-		$	-
Summary of effective income tax rate differed from the statutory U.S. federal income tax rate	'
		Year Ended
		December 31,			December 31,
		2013			2012
	Federal income tax rate		(35.0	)%		(35.0	)%
	State income taxes, net of federal benefit		(3.7	)		(3.6	)
	Percentage depletion in excess of basis		3.9			0.1
	Non-controlling interest in consolidated partnerships		1.3			4.4
	True-up of prior year depletion in excess of basis		5.7			-
	Rate changes of prior year deferreds		(3.9	)		1.8
	Increase in valuation allowance and other		31.7			32.3
	Total income tax (benefit)		0	%		0	%
Summary of deferred tax assets and liabilities	'
	(in thousands)
		December 31,			December 31,
		2013			2012
	Deferred tax assets
	Net operating loss carryforwards	$	6,754		$	5,777
	Depletion carryforwards		1,435			1,022
	Accrual and other		1,043			713
	Derivatives		125			33
	Asset retirement obligations		1,024			884
	Property, plant and equipment		5,009			8,083
	Total deferred tax assets		15,390			16,512
	Deferred tax liability
	Interest in partnerships		(475	)		(279	)
	Less valuation allowance		(14,915	)		(16,233	)
	Net deferred tax asset	$	-		$	-

Stockholders_Equity_Tables

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Class Of Stock [Line Items]	'
Summary of number of shares and exercise price of options outstanding and exercisable	'
			Number of			Weighted		Weighted
			Shares			Average		Average
						Exercise Price		Remaining
								Contractual Life
								(Years)
	Outstanding – January 1, 2012			269,075		$	0.63		4.4
	Forfeited			(105,999	)		0.67
	Outstanding – December 31, 2012			163,076			0.61		3
	Outstanding – December 31, 2013			163,076			0.61		2
	Exercisable – December 31, 2013			163,076		$	0.61		2
Summarizes assumptions used to estimate grant date fair value	'
	Risk-free interest rate	0.39%
	Company expected volatility	92.92%
	Expected term	2.87 years
	Dividend yield	-
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, 2012			-
	Granted			1,290,000
	Forfeited			(123,840	)
	Restricted performance units, non-vested, December 31, 2012			1,166,160
	Granted			1,920,000
	Restricted performance units, non-vested, December 31, 2013			3,086,160
Carbon 2011 Stock Incentive Plan [Member]	'
Class Of Stock [Line Items]	'
Summary of Company's unvested restricted stock	'
						Weighted Avg
			Number			Grant Due
			of Shares			Fair Value
	Restricted stock awards, nonvested, January 1, 2012			-			N/A
	Granted			1,610,000		$	0.62
	Restricted stock awards, nonvested, December 31, 2012			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

Accounts_Payable_and_Accrued_L1

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts Payable and Accrued Liabilities [Abstract]	'
Summary of accounts payable and accrued liabilities	'
	(in thousands)
		As of December 31,
		2013		2012
	Accounts payable	$	2,151	$	790
	Oil and gas revenue payable to oil and gas property owners		1,307		1,886
	Production taxes payable		165		123
	Drilling advances received from joint venture partner		740		537
	Accrued drilling costs		162	75
	Accrued lease operating costs		42		61
	Accrued ad valorem taxes		681		596
	Accrued general and administrative expenses		1,146		1,083
	Accrued other		211		253
	Total accounts payable and accrued liabilities	$	6,605	$	5,404

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Summary of financial assets and liabilities at fair value	'
	(in thousands)	Fair Value Measurements Using
		Level 1		Level 2		Level 3		Total
	31-Dec-13
	Liabilities:
	Commodity derivatives	$	-	$	326	$	-	$	326
	31-Dec-12
	Liabilities:
	Commodity derivatives	$	-	$	87	$	-	$	87

Physical_Delivery_Contracts_an1

Physical Delivery Contracts and Commodity Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
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 2014		210,000			$	4.01				9,000			$	93.24
	Apr - Jun 2014		210,000			$	4.05				9,000			$	93.24
	Jul - Sep 2014		210,000			$	4.05				6,000			$	93.14
	Oct - Dec 2014		190,000			$	4.04				6,000			$	93.14
	Jan - Mar 2015		190,000			$	3.98				-				-
	Apr - Jun 2015		150,000			$	4.02				-				-
	Jul - Sep 2015		150,000			$	4.02				-				-
	Oct - Dec 2015		150,000			$	4.02				-				-
	(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	'
		As of December 31,
		2013				2012
	Commodity derivative contracts:
	Current liabilities	$	326			$	87
Schedule of realized and unrealized gains and losses	'
		For the year ended December 31,
		2013				2012
	Commodity derivative contracts:
	Realized (losses) gains	$	(220	)		$	454
	Unrealized losses		(239	)			(395	)
	Total realized and unrealized (losses) gains, net	$	( 459	)		$	59
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		$	26			$	(26	)		$	-
		Other long-term assets			3				(3	)			-
	Total derivative assets			$	29			$	(29	)		$	-
	Commodity derivative liabilities:	Current derivative liability			252				(26	)			226
		Long-term derivative liability			103				(3	)			100
	Total derivative liabilities			$	355			$	(29	)		$	326

Commitments_Tables

Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments [Abstract]	'
Summary of firm transportation volumes and related demand charges	'
	Period	Dekatherms per day	Demand Charges
	Jan - Mar 2014	7,250	$0.20 - $0.67
	Apr - Oct 2014	6,450	$0.20 - $0.67
	Nov 2014 - May 2015	4,450	$0.20 - $0.67
	Jun 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
	Dec. 31, 2013
Supplemental Cash Flow Disclosures [Abstract]	'
Supplemental cash flow disclosures	'
		For the Year Ended December 31,
		2013		2012
	Cash paid for interest payments	$	548	$	590
	Non-cash transactions:
	Increase (decrease) in net asset retirement obligations	$	240	$	75
	Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	$	1,046	$	1,772
	Receivables due from partners assumed in acquisitions	$	20	$	-

Supplemental_Financial_Data_Oi1

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
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	'
		2013									2012
		Oil			Natural Gas			Total			Oil			Natural Gas			Total
		MBbls			MMcf			MMcfe			MBbls			MMcf			MMcfe
	Proved reserves, beginning of year		872			33,646			38,878			732			62,952			67,344
	Revisions of previous estimates		(249	)		3,459			1,965			(236	)		(27,163	)		(28,579	)
	Extensions and discoveries		305			1,394			3,224			457			274			3,016
	Production		(107	)		(2,252	)		(2,894	)		(52	)		(2,417	)		(2,729	)
	Purchases of reserves in-place		1			437			443			-			-			-
	Sales of reserves in-place		-			-			-			(29	)		-			(174	)
	Proved reserves, end of year		822			36,684			41,616			872			33,646			38,878
	Proved developed reserves at:
	End of year		748			35,317			39,805			489			33,398			36,332
	Proved undeveloped reserves at:
	End of year		74			1,367			1,811			383			248			2,546
Summary of aggregate capitalized costs relating to oil and gas producing activities	'
		2013			2012
		(in thousands)
	Oil and gas properties
	Proved oil and gas properties	$	100,769		$	91,132
	Unproved properties not subject to depletion		2,235			1,126
	Accumulated depreciation, depletion, amortization and impairment		(61,736	)		(58,946	)
	Net oil and gas properties	$	41,268		$	33,312
Summary of costs incurred in oil and gas property acquisition, exploration, and development activities	'
		2013			2012
		(in thousands)
	Property acquisition costs:
	Unevaluated properties	$	1,117		$	509
	Proved and unproved properties and gathering facilities		501			378
	Development costs		7,818			5,734
	Gathering facilities		1			227
	Asset retirement obligations		240			75
	Total costs incurred	$	9,677		$	6,923
Summary of company's investment in unproved properties	'
		2013			2012			2011 and Prior
		(in thousands)
	Acquisition costs	$	1,117		$	509		$	609
Summary of results of operations from oil and gas producing activities	'
		2013			2012
		(in thousands)
	Oil and gas sales, including commodity derivative gains	$	18,222		$	11,809
	Expenses:
	Production expenses		5,487			5,278
	Depletion expense		2,789			3,037
	Ceiling test write-down of oil and gas properties		-			15,407
	Accretion of asset retirement obligations		138			105
	Total expenses		8,414			23,827
	Results of operations from oil and gas producing activities	$	9,808		$	(12,018	)
	Depletion rate per Mcfe	$	0.96		$	1.11
Summary of estimate of the current market value of the Company's proved reserves	'
		December 31,
		2013			2012
		(in thousands)
	Future cash inflows	$	218,545		$	174,832
	Future production costs		(91,013	)		(68,192	)
	Future development costs		(4,152	)		(2,813	)
	Future income taxes		(13,920	)		(8,078	)
	Future net cash flows		109,460			95,749
	10% annual discount		(53,018	)		(50,157	)
	Standardized measure of discounted future net cash flows	$	56,442		$	45,592
Summary of discounted future cash flows relating to proved oil and gas reserves	'
		December 31,
		2013			2012
		(in thousands)
	Standardized measure of discounted future net cash flows, beginning of year	$	45,592		$	48,889
	Sales of oil and gas, net of production costs and taxes		(13,194	)		(6,471	)
	Price revisions		2,852			(23,045	)
	Extensions, discoveries and improved recovery, less related costs		10,869			13,892
	Changes in estimated future development costs		980			30,777
	Development costs incurred during the period		782			835
	Quantity revisions		2,513			(15,395	)
	Accretion of discount		4,559			4,889
	Net changes in future income taxes		-			-
	Purchases of reserves-in-place		293			-
	Sales of reserves-in-place		-			(213	)
	Changes in production rates timing and other		1,196			(8,566	)
	Standardized measure of discounted future net cash flows, end of year	$	56,442		$	45,592
Summary of weighted averaged adjusted prices	'
		2013			2012
	Oil (per Bbl)	$	94.08		$	91.88
	Natural Gas (per Mcf)	$	3.84		$	2.8

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details 1)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Purchaser A [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentages by purchaser	39.00%	34.00%
Purchaser B [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentages by purchaser	22.00%	29.00%
Purchaser C [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentages by purchaser	11.00%	'
Purchaser D [Member]	'	'
Concentration Risk [Line Items]	'	'
Percentages by purchaser	7.00%	10.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Summary of reconciliation of the ARO	'	'
Balance at beginning of year	$2,321	$2,149
Accretion expense	138	105
Additions during period	123	75
Additions assumed with acquired properties	117	'
Costs incurred	'	-8
Balance at end of year	$2,699	$2,321

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Details Textual) (USD $)	12 Months Ended
Share data in Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
	Partnership
Summary of Significant Accounting Policies (Textual)	'	'
Purchaser imbalance liability	$117,000	'
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%	'
Impairment Of Oil and Gas Properties	'	15,407,000
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	4.7
Restricted Performance Units [Member]	'	'
Summary of Significant Accounting Policies (Textual)	'	'
Common stock equivalent restricted to future contingencies	$3,200,000	'
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 $)	31-May-13	Sep. 30, 2012
		Participation agreement [Member]
		Well
Dispositions and Acquisitions (Textual)	'	'
Payment to Nytis LLC under agreement	'	$3,700,000
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	$517,000	'

Property_and_Equipment_Details

Property and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and gas properties	'	'
Accumulated depreciation, depletion, amortization and impairment	($61,736)	($58,946)
Net oil and gas properties	41,268	33,312
Furniture and fixtures, computer hardware and software, and other equipment	960	782
Accumulated depreciation and amortization	-673	-540
Net other property and equipment	287	242
Total property and equipment	41,555	33,554
Proved oil and gas properties [Member]	'	'
Oil and gas properties	'	'
Oil and gas properties, gross	100,769	91,132
Unproved properties not subject to depletion [Member]	'	'
Oil and gas properties	'	'
Oil and gas properties, gross	$2,235	$1,126

Property_and_Equipment_Details1

Property and Equipment (Details 1) (Unproved properties not subject to depletion [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	$2,235	$1,126
Indiana [Member]	'	'
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	446	432
Illinois [Member]	'	'
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	354	314
Kentucky [Member]	'	'
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	1,367	314
Ohio [Member]	'	'
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	66	65
West Virginia [Member]	'	'
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]	'	'
Oil and gas properties, gross	$2	$1

Property_and_Equipment_Details2

Property and Equipment (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	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	$483,000	$529,000
Depletion expense related to oil and gas properties	2,800,000	3,000,000
Depletion expense related to oil and gas properties (in dollars per Mcfe)	0.96	1.11
Depreciation and amortization expense	133,000	99,000
Proved property	4,000	55,000
Unproved properties not subject to depletion [Member]	'	'
Property and Equipment (Textual)	'	'
Oil and gas properties, gross	$2,235,000	$1,126,000

Equity_Method_Investment_Detai

Equity Method Investment (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
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	($91)	$4

Bank_Credit_Facility_Details

Bank Credit Facility (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
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 2017
Maximum borrowing base	50
Outstanding borrowings	12.8
Additional borrowing capacity available	$7.20
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, 2013	Dec. 31, 2012
Summary of provision for income taxes	'	'
Current income tax (benefit) expense	'	'
Deferred income tax (benefit) expense	1,351	-5,647
Change in valuation allowance	-1,351	5,647
Total income tax (benefit) expense	'	'

Income_Taxes_Details_1

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
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	-3.70%	-3.60%
Percentage depletion in excess of basis	3.90%	0.10%
Non-controlling interest in consolidated partnerships	1.30%	4.40%
True-up of prior year depletion in excess of basis	5.70%	'
Rate changes of prior year deferreds	-3.90%	1.80%
Increase in valuation allowance and other	31.70%	32.30%
Total income tax (benefit)	0.00%	0.00%

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets	'	'
Net operating loss carryforwards	$6,754	$5,777
Depletion carryforwards	1,435	1,022
Accrual and other	1,043	713
Derivatives	125	33
Asset retirement obligations	1,024	884
Property, plant and equipment	5,009	8,083
Total deferred tax assets	15,390	16,512
Deferred tax liability	'	'
Interest in partnerships	-475	-279
Less valuation allowance	-14,915	-16,233
Net deferred tax asset	'	'

Income_Taxes_Details_Textual

Income Taxes (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Income Taxes (Textual)	'
Net operating losses	$17.20
Operating loss expiration year	'expire in 2032
Net operating losses carryforward	$18.20

Stockholders_Equity_Details

Stockholders' Equity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of number of shares and exercise price of options outstanding and exercisable	'	'	'
Number of Shares Outstanding, Beginning balance	163,076	269,075	'
Number of Shares, Forfeited	'	-105,999	'
Number of Shares Outstanding, Ending Balance	163,076	163,076	269,075
Number of Shares Exercisable	163,076	'	'
Weighted Average Exercise Price Options Outstanding, Beginning Balance	$0.61	$0.63	$0.64
Weighted Average Exercise Price Options, Forfeited	'	$0.67	'
Weighted Average Exercise Price Options Outstanding, Ending Balance	$0.61	$0.61	$0.63
Weighted Average Exercise Price Options Exercisable	$0.61	$0.61	'
Weighted Average Remaining Contractual Life (Years) Options Outstanding	'2 years	'3 years	'4 years 4 months 24 days
Weighted Average Remaining Contractual Life (Years) Options Exercisable	'2 years	'	'

Stockholders_Equity_Details_1

Stockholders' Equity (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Performance Units [Member]	'	'
Summary of Company's unvested restricted stock	'	'
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	1,166,160	'
Granted, Number of Shares	1,920,000	1,290,000
Forfeited, Number of Shares	'	-123,840
Restricted stock awards, nonvested, Ending Balance, Number of Shares	3,086,160	1,166,160
Carbon 2011 Stock Incentive Plan [Member]	'	'
Summary of Company's unvested restricted stock	'	'
Restricted stock awards, nonvested, Beginning Balance, Number of Shares	1,610,000	'
Granted, Number of Shares	1,600,000	1,610,000
Vested, Number of Shares	-429,997	'
Restricted stock awards, nonvested, Ending Balance, Number of Shares	2,780,003	1,610,000
Restricted stock awards, nonvested, Beginning Balance, Weighted Avg Grant Due Fair Value	0.62	'
Granted, Weighted Avg Grant Due Fair Value	0.64	0.62
Vested, Weighted Avg Grant Due Fair Value	0.62	'
Restricted stock awards, nonvested, Ending Balance, Weighted Avg Grant Due Fair Value	0.63	0.62

Stockholders_Equity_Details_2

Stockholders' Equity (Details 2)	12 Months Ended
	Dec. 31, 2013
Summary of assumptions used to estimate grant date fair value	'
Risk-free interest rate	0.39%
Company expected volatility	92.92%
Expected term	'2 years 10 months 13 days
Dividend yield	'

Stockholders_Equity_Details_Te

Stockholders' Equity (Details Textual) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 25, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2010

Dec. 31, 2005

Dec. 31, 2005

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Restricted Performance Units [Member]

Equity Plans Prior To Merger [Member]

Equity Plans Prior To Merger [Member]

Equity Plans Prior To Merger [Member]

Equity Plans Prior To Merger [Member]

Equity Plans Prior To Merger [Member]

Nytis USA Restricted Stock Plan [Member]

Nytis USA Restricted Stock Plan [Member]

Carbon 2011 Stock Incentive Plan [Member]

Nytis USA [Member]

Nytis USA [Member]

Nytis USA [Member]

Nytis USA [Member]

Nytis USA [Member]

Nytis USA [Member]

Carbon Natural Gas Company [Member]

Carbon Natural Gas Company [Member]

Carbon Natural Gas Company [Member]

Carbon Natural Gas Company [Member]

Carbon Natural Gas Company [Member]

Stock Options [Member]

Warrant [Member]

Warrant [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Officer [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Warrant [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Stock Units (RSUs) [Member]

Restricted Performance Units [Member]

Officer [Member]

Employee [Member]

Non Employee [Member]

Stockholders' Equity (Textual)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares authorized

1,000,000

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, par value (in dollars per share)

$0.01

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares outstanding

163,076

163,076

269,075

'

163,076

2,696,133

2,696,133

1,956,907

1,956,912

'

'

'

2,696,133

'

'

'

1,956,907

1,956,912

'

'

'

'

1,096,500

Number of Shares Exercisable

163,076

'

'

'

163,076

2,696,133

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of options granted in period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,446,133

'

'

'

'

'

'

'

Number of warrants granted by SLSC

'

'

'

'

'

250,000

'

'

'

'

'

'

250,000

'

'

'

'

'

'

'

'

'

'

Number of shares issuable upon conversion of each option

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

Exercise price

'

'

'

'

'

'

'

'

'

'

'

'

$1

$0.85

$0.61

'

'

'

'

'

'

'

'

Expiration date

'

'

'

'

'

'

'

'

'

'

'

'

31-Aug-17

'

1-Jun-15

'

'

'

'

'

'

'

'

Increasing percentage of exercise price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

Common stock authorized for issuance to officers

'

'

'

'

'

'

'

'

'

'

'

12,600,000

'

'

'

'

'

'

'

'

'

'

'

Grant date fair value

'

'

'

$0.54

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compensation cost recognized

'

'

'

$218,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$526,000

$300,000

'

'

'

Common stock, shares authorized

200,000,000

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Vesting, percentage

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Compensation costs for restricted stock grants

'

'

'

'

'

'

'

'

'

'

168,000

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost

'

'

'

$818,000

'

'

'

'

'

'

$1,000,000

'

'

'

'

'

'

'

$1,200,000

'

'

'

$991,000

Amortization period of recognized compensation expense

'

'

'

'

'

'

'

'

'

'

'3 years 6 months

'

'

'

'

'

'

'

'

'

'3 years

'3 years

'

Expected period of recognition of unrecognized compensation costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years 3 months 18 days

'

'

'

'

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.

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, par value (in dollars per share)

$0.01

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares issued

114,470,223

115,795,405

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares outstanding

114,470,223

115,795,405

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts_Payable_and_Accrued_L2

Accounts Payable and Accrued Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Summary of accounts payable and accrued liabilities	'	'
Accounts payable	$2,151	$790
Oil and gas revenue payable to oil and gas property owners	1,307	1,886
Production taxes payable	165	123
Drilling advances received from joint venture partner	740	537
Accrued drilling costs	162	75
Accrued lease operating costs	42	61
Accrued ad valorem taxes	681	596
Accrued general and administrative expenses	1,146	1,083
Accrued other	211	253
Total accounts payable and accrued liabilities	$6,605	$5,404

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Liabilities:	'	'
Commodity derivatives	$226	$87
Recurring basis [Member]	'	'
Liabilities:	'	'
Commodity derivatives	326	87
Recurring basis [Member] | Level 1 [Member]	'	'
Liabilities:	'	'
Commodity derivatives	'	'
Recurring basis [Member] | Level 2 [Member]	'	'
Liabilities:	'	'
Commodity derivatives	326	87
Recurring basis [Member] | Level 3 [Member]	'	'
Liabilities:	'	'
Commodity derivatives	'	'

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Agreements	Agreements
Fair Value Measurements (Textual)	'	'
Asset retirement obligations	240,000	75,000
Swap [Member] | Oil [Member]	'	'
Fair Value Measurements (Textual)	'	'
Number of agreements	5	2
Swap [Member] | Natural Gas [Member]	'	'
Fair Value Measurements (Textual)	'	'
Number of agreements	9	2

Physical_Delivery_Contracts_an2

Physical Delivery Contracts and Commodity Derivatives (Details) (Swap [Member])	Dec. 31, 2013
Jan - Mar 2014 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	210,000
Weighted Average Price	4.01	[1]
Jan - Mar 2014 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	9,000
Weighted Average Price	93.24	[2]
Apr - Jun 2014 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	210,000
Weighted Average Price	4.05	[1]
Apr - Jun 2014 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	9,000
Weighted Average Price	93.24	[2]
Jul - Sep 2014 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	210,000
Weighted Average Price	4.05	[1]
Jul - Sep 2014 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	6,000
Weighted Average Price	93.14	[2]
Oct - Dec 2014 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	190,000
Weighted Average Price	4.04	[1]
Oct - Dec 2014 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	6,000
Weighted Average Price	93.14	[2]
Jan - Mar 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	190,000
Weighted Average Price	3.98	[1]
Jan - Mar 2015 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	'
Weighted Average Price	'	[2]
Apr - Jun 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	150,000
Weighted Average Price	4.02	[1]
Apr - Jun 2015 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	'
Weighted Average Price	'	[2]
Jul - Sep 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	150,000
Weighted Average Price	4.02	[1]
Jul - Sep 2015 [Member] | Oil [Member] | NYMEX Light Sweet Crude West Texas Intermediate Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	'
Weighted Average Price	'	[2]
Oct - Dec 2015 [Member] | Natural Gas [Member] | NYMEX Henry Hub Natural Gas Futures Contract [Member]	'
Summary of swap agreements	'
Quantity	150,000
Weighted Average Price	4.02	[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]
[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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity derivative contracts:	'	'
Current liabilities	$226	$87

Physical_Delivery_Contracts_an4

Physical Delivery Contracts and Commodity Derivatives (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Commodity derivative contracts:	'	'
Unrealized losses	($239)	($395)
Commodity derivative contracts [Member]	'	'
Commodity derivative contracts:	'	'
Realized (losses) gains	-220	454
Unrealized losses	-239	-395
Total realized and unrealized (losses) gains, net	($459)	$59

Physical_Delivery_Contracts_an5

Physical Delivery Contracts and Commodity Derivatives (Details 3) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity derivative liabilities:	'	'
Current liabilities	$226	$87
Long-term derivative liability	100	'
Gross Recognized Assets/Liabilities [Member]	'	'
Commodity derivative assets:	'	'
Current derivative asset	26	'
Other long-term assets	3	'
Total derivative assets	29	'
Commodity derivative liabilities:	'	'
Current liabilities	252	'
Long-term derivative liability	103	'
Total derivative liabilities	355	'
Gross Amounts Offset [Member]	'	'
Commodity derivative assets:	'	'
Current derivative asset	-26	'
Other long-term assets	-3	'
Total derivative assets	-29	'
Commodity derivative liabilities:	'	'
Current liabilities	-26	'
Long-term derivative liability	-3	'
Total derivative liabilities	-29	'
Net Recognized Fair Value Assets/Liabilities [Member]	'	'
Commodity derivative assets:	'	'
Current derivative asset	'	'
Other long-term assets	'	'
Total derivative assets	'	'
Commodity derivative liabilities:	'	'
Current liabilities	226	'
Long-term derivative liability	100	'
Total derivative liabilities	$326	'

Physical_Delivery_Contracts_an6

Physical Delivery Contracts and Commodity Derivatives (Details Textual) (Natural Gas [Member], January 2014 through March 2014 [Member])	12 Months Ended
	Dec. 31, 2013
	Price_Mcfperday
	Price_Per_Mcfs
Natural Gas [Member] | January 2014 through March 2014 [Member]	'
Physical Delivery Contracts and Commodity Derivatives (Textual)	'
Physical deliveries required for fixed price contracts (in Mcf per month)	250
Average sales price (in dollars per Mcf)	4.13

Commitments_Details

Commitments (Details) (Long-term transportation contracts [Member])	12 Months Ended
	Dec. 31, 2013
	Dekatherm
Jan - Mar 2014 [Member]	'
Supply Commitment [Line Items]	'
Capacity levels (Dekatherms per day)	7,250
Apr - Oct 2014 [Member]	'
Supply Commitment [Line Items]	'
Capacity levels (Dekatherms per day)	6,450
Nov 2014 - May 2015 [Member]	'
Supply Commitment [Line Items]	'
Capacity levels (Dekatherms per day)	4,450
Jun 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 - Mar 2014 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.67
Maximum [Member] | Apr - Oct 2014 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.67
Maximum [Member] | Nov 2014 - May 2015 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.67
Maximum [Member] | Jun 2015 - Dec 2017 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.67
Minimum [Member] | Jan - Mar 2014 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.2
Minimum [Member] | Apr - Oct 2014 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.2
Minimum [Member] | Nov 2014 - May 2015 [Member]	'
Supply Commitment [Line Items]	'
Demand charges (in dollars per dekatherm)	0.2
Minimum [Member] | Jun 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
	Dec. 31, 2013	Dec. 31, 2012
Commitments (Textual)	'	'
Rental expenses incurred	$189,000	$148,000
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	'
Lease expiration date	31-Dec-16	'
Office space and equipment [Member]	'	'
Commitments (Textual)	'	'
Minimum lease payments for 2014	260,000	'
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 initial term of the agreements generally range from one to three years and provide for renewal provisions in one year increments thereafter.
Liability related to firm transportation contracts assumed	$1,900,000	'

Retirement_Savings_Plan_Detail

Retirement Savings Plan (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Retirement Savings Plan (Textual)	'	'
Matching percentage under retirement savings plan	6.00%	'
401(K) contributions and related administrative expenses	$192,000	$168,000

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Related Party Transactions (Textual)	'	'
Management fee received	'	$90,000
Date for termination of services agreement	'	30-Jun-12
Monthly fee charged by company	$15,000	'

Supplemental_Cash_Flow_Disclos2

Supplemental Cash Flow Disclosures (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cash paid during the period for:	'	'
Cash paid for interest payments	$548	$590
Non-cash transactions:	'	'
Increase (decrease) in net asset retirement obligations	240	75
Increase (decrease) in accounts payable and accrued liabilities included in oil and gas properties	1,046	1,772
Receivables due from partners assumed in acquisitions	$20	'

Subsequent_Event_Details_Textu

Subsequent Event (Details Textual) (Subsequent Event [Member], Second Participation Agreement [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
	Well
Subsequent Event [Member] | Second Participation Agreement [Member]	'
Subsequent Event [Line Items]	'
Payment to Nytis LLC under agreement	$1.70
Working interest percentage in covered leases, Nytis LLC assigned to Liberty	40.00%
Area Covered	'
	Nytis LLC has the right to provide additional net mineral acres prior to the later of (a) December 31, 2014 or (b) the date that is nine (9) months after the date that the last well was spud in the covered area and, upon delivery of a maximum amount of additional net mineral acres
Additional Payments to Nythis LLC	$1.10
Number Of Wells Under Second Participation Agreement	20
Mineral Acres Associated With Leases	'
	Liberty has committed to participate on the basis described above in one (1) well per 1,000 net mineral acres associated with the covered leases

Supplemental_Financial_Data_Oi2

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MMcf	MMcf	MMcf	MMcf
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells	'	'	'	'
Proved reserves, beginning of year	38,878	67,344	'	55,536
Revisions of previous estimates	1,965	-28,579	'	'
Extensions and discoveries	3,224	3,016	'	'
Production	-2,894	-2,729	'	'
Purchases of reserves in-place	443	'	'	'
Sales of reserves in-place	'	-174	'	'
Proved reserves, end of year	41,616	38,878	'	55,536
Proved developed reserves at:	'	'	'	'
End of year	39,805	36,332	46,572	'
Proved undeveloped reserves at:	'	'	'	'
End of year	1,811	2,546	20,772	'
Oil [Member]	'	'	'	'
Summary of Proved undeveloped and developed oil and gas reserves expected to be recovered from new wells	'	'	'	'
Proved reserves, beginning of year	872	732	'	146
Revisions of previous estimates	-249	-236	'	'
Extensions and discoveries	305	457	'	'
Production	-107	-52	'	'
Purchases of reserves in-place	1	'	'	'
Sales of reserves in-place	'	-29	'	'
Proved reserves, end of year	822	872	'	146
Proved developed reserves at:	'	'	'	'
End of year	748	489	411	'
Proved undeveloped reserves at:	'	'	'	'
End of year	74	383	321	'
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	33,646	62,952	'	54,660
Revisions of previous estimates	3,459	-27,163	'	'
Extensions and discoveries	1,394	274	'	'
Production	-2,252	-2,417	'	'
Purchases of reserves in-place	437	'	'	'
Sales of reserves in-place	'	'	'	'
Proved reserves, end of year	36,684	33,646	'	54,660
Proved developed reserves at:	'	'	'	'
End of year	35,317	33,398	44,103	'
Proved undeveloped reserves at:	'	'	'	'
End of year	1,367	248	18,849	'

Supplemental_Financial_Data_Oi3

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and gas properties	'	'
Proved oil and gas properties	$100,769	$91,132
Unproved properties not subject to depletion	2,235	1,126
Accumulated depreciation, depletion, amortization and impairment	-61,736	-58,946
Net oil and gas properties	$41,268	$33,312

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Property acquisition costs:	'	'	'
Unevaluated properties	$1,117	$509	$609
Proved and unproved properties and gathering facilities	501	378	'
Development costs	7,818	5,734	'
Gathering facilities	1	227	'
Asset retirement obligations	240	75	'
Total costs incurred	$9,677	$6,923	'

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of company's investment in unproved properties	'	'	'
Acquisition costs	$1,117	$509	$609

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, 2013	Dec. 31, 2012
	Mcf	Mcf
Summary of results of operations from oil and gas producing activities	'	'
Oil and gas sales, including commodity derivative gains	$18,222	$11,809
Expenses:	'	'
Production expenses	5,487	5,278
Depletion expense	2,789	3,037
Ceiling test write-down of oil and gas properties	'	15,407
Accretion of asset retirement obligations	138	105
Total expenses	8,414	23,827
Results of operations from oil and gas producing activities	$9,808	($12,018)
Depletion rate per Mcfe	0.96	1.11

Supplemental_Financial_Data_Oi7

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Summary of estimate of the current market value of the Company's proved reserves	'	'
Future cash inflows	$218,545	$174,832
Future production costs	-91,013	-68,192
Future development costs	-4,152	-2,813
Future income taxes	-13,920	-8,078
Future net cash flows	109,460	95,749
10% annual discount	-53,018	-50,157
Standardized measure of discounted future net cash flows	$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, 2013	Dec. 31, 2012	Dec. 31, 2010
Summary of discounted future cash flows relating to proved oil and gas reserves	'	'	'
Standardized measure of discounted future net cash flows, beginning of year	$45,592	$48,889	$20,952
Sales of oil and gas, net of production costs and taxes	-13,194	-6,471	'
Price revisions	2,852	-23,045	'
Extensions, discoveries and improved recovery, less related costs	10,869	13,892	'
Changes in estimated future development costs	980	30,777	'
Development costs incurred during the period	782	835	'
Quantity revisions	2,513	-15,395	'
Accretion of discount	4,559	4,889	'
Net changes in future income taxes	'	'	'
Purchases of reserves-in-place	293	'	'
Sales of reserves-in-place	'	-213	'
Changes in production rates timing and other	1,196	-8,566	'
Standardized measure of discounted future net cash flows, end of year	$56,442	$45,592	$20,952

Supplemental_Financial_Data_Oi9

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details 7)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Oil (per Bbl) [Member]	'	'
Summary of weighted averaged adjusted prices	'	'
Weighted averaged adjusted prices	94.08	91.88
Natural Gas (per Mcf) [Member]	'	'
Summary of weighted averaged adjusted prices	'	'
Weighted averaged adjusted prices	3.84	2.8

Recovered_Sheet1

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited) (Details Textual)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	MMBbls	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	74
Decrease of previous oil estimates associated with offset	161	163
Discount rate, description	'	'
	All cash flow amounts, including income taxes, are discounted at 10%.