Escalera Resources (ESCR) 10-K 13 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 07, 2014	Jun. 28, 2013
Document Document And Entity Information [Line Items]	'	'	'
Entity Registrant Name	'DOUBLE EAGLE PETROLEUM CO	'	'
Entity Central Index Key	'0000029834	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Smaller Reporting Company	'	'
Entity Public Float	'	'	$43,263,340
Entity Common Stock, Shares Outstanding	'	11,693,130	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$2,799	$4,070
Cash held in escrow	283	565
Accounts receivable, net	5,111	6,608
Assets from price risk management	205	6,742
Other current assets	3,130	3,024
Total current assets	11,528	21,009
Oil and gas properties and equipment, successful efforts method:	'	'
Developed properties	238,332	225,382
Wells in progress	2,342	10,963
Gas transportation pipeline	5,510	5,510
Undeveloped properties	2,705	2,734
Corporate and other assets	2,041	2,068
Total oil and gas properties and equipment, successful efforts method	250,930	246,657
Less accumulated depreciation, depletion and amortization	-130,518	-109,606
Net properties and equipment	120,412	137,051
Assets from price risk management	402	682
Other assets	58	68
TOTAL ASSETS	132,400	158,810
Current liabilities:	'	'
Accounts payable and accrued expenses	7,327	11,052
Accrued production taxes	2,275	1,906
Other current liabilities	222	200
Total current liabilities	9,824	13,158
Credit facility	47,450	47,450
Asset retirement obligation	8,420	8,494
Liabilities from price risk management	97	'
Deferred tax liability	1,236	7,896
Other long-term liabilities	90	370
Total liabilities	67,117	77,368
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of December 31, 2013 and December 31, 2012	37,972	37,972
Stockholders' equity:	'	'
Common stock, $0.10 par value; 50,000,000 shares authorized; issued 11,517,261 and 11,452,473 outstanding at December 31, 2013 and 11,305,043 issued and 11,279,268 outstanding at December 31, 2012	1,145	1,128
Additional paid-in capital	42,302	45,405
Accumulated deficit	-16,136	-3,063
Total stockholders' equity	27,311	43,470
TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY	$132,400	$158,810

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Preferred stock, par value	$0.10	$0.10
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	1,610,000	1,610,000
Preferred stock, shares outstanding	1,610,000	1,610,000
Common stock, par value	$0.10	$0.10
Common stock, shares authorized	50,000,000	50,000,000
Common stock, shares issued	11,517,261	11,305,043
Common stock, shares outstanding	11,452,473	11,279,268

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Oil and gas sales	$31,784	$26,574	$44,160
Transportation and gathering revenue	3,745	4,999	4,894
Price risk management activities	-730	4,939	14,740
Other income	520	1,653	909
Total revenues	35,319	38,165	64,703
Costs and expenses	'	'	'
Production costs	13,135	12,299	11,047
Production taxes	3,906	3,000	4,365
Exploration expenses including dry hole costs	181	696	273
Pipeline operating costs	5,194	4,892	4,114
Impairment and abandonment of equipment and properties	4,992	4,988	187
General and administrative	5,395	6,209	6,107
Depreciation, depletion and amortization	20,942	20,216	18,844
Total costs and expenses	53,745	52,300	44,937
Income (loss) from operations	-18,426	-14,135	19,766
Interest expense, net	-1,307	-1,610	-1,317
Income (loss) before income taxes	-19,733	-15,745	18,449
Benefit (provision) for deferred income taxes	6,660	5,418	-6,762
NET INCOME (LOSS)	-13,073	-10,327	11,687
Preferred stock dividends	-3,723	-3,723	-3,723
Net income (loss) attributable to common stock	($16,796)	($14,050)	$7,964
Net income (loss) per common share:	'	'	'
Basic	($1.48)	($1.25)	$0.71
Diluted	($1.48)	($1.25)	$0.71
Weighted average shares outstanding:	'	'	'
Basic	11,332,129	11,250,513	11,191,496
Diluted	11,332,129	11,250,513	11,210,604

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income (loss)	($13,073)	($10,327)	$11,687
Other comprehensive income (loss), net of tax	'	'	'
Change in derivative instrument fair value	'	'	556
Reclassification to earnings	'	'	-6,124
Total other comprehensive income (loss), net of tax	'	'	-5,568
Comprehensive income (loss)	($13,073)	($10,327)	$6,119

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income (loss)	($13,073)	($10,327)	$11,687
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion, amortization and accretion of asset retirement obligation	21,218	20,404	19,018
Impairment and abandonment of equipment and properties	4,992	4,988	187
Dry hole costs	'	481	'
Settlement of asset retirement obligation	-126	-9	'
Revenue from carried interest	'	'	-117
Provision for deferred taxes	-6,660	-5,418	6,762
Change in fair value of derivative contracts	6,656	7,933	-13,760
Stock-based compensation expense	744	1,341	1,153
Loss (gain) on sale of producing property	13	-1,669	-627
Changes in current assets and liabilities:	'	'	'
Decrease (Increase) in deposit held in escrow	282	-1	51
Decrease (Increase) in accounts receivable	1,497	-1,082	527
Decrease in other current assets	435	397	612
(Decrease) Increase in accounts payable and accrued expenses	-3,265	3,114	-544
Decrease in accrued production taxes	369	-684	-167
NET CASH PROVIDED BY OPERATING ACTIVITIES	13,082	19,468	24,782
Cash flows from investing activities:	'	'	'
Payments to acquire and develop producing properties and equipment, net	-10,516	-27,388	-23,958
Payments to acquire corporate and non-producing properties	-7	-25	-359
Sales of oil and gas properties and equipment	'	1,640	371
NET CASH USED IN INVESTING ACTIVITIES	-10,523	-25,773	-23,946
Cash flows from financing activities:	'	'	'
Dividends paid on preferred stock	-3,723	-3,723	-3,723
Net borrowings on credit facility	'	5,450	10,000
Deferred financing costs	'	'	-450
Principal payments on capital lease obligations	'	'	-545
Tax withholdings related to net share settlement of restricted stock awards	-107	-30	-45
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	-3,830	1,697	5,237
Change in cash and cash equivalents	-1,271	-4,608	6,073
Cash and cash equivalents at beginning of period	4,070	8,678	2,605
CASH AND CASH EQUIVALENTS AT END OF PERIOD	2,799	4,070	8,678
Supplemental disclosure of cash and non-cash transactions:	'	'	'
Cash paid for interest	1,641	1,173	1,352
Interest capitalized	80	321	155
Cash paid for income taxes	'	'	'
Additions to developed properties included in current liabilities	1,671	2,265	6,489
Additions/reductions to developed properties for retirement obligations	-91	12	277
Receivables due from joint-interest partners related to change in working interest	'	$657	'

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (loss)
In Thousands, except Share data
Beginning balance at Dec. 31, 2010	$52,705	$1,116	$44,583	$1,438	$5,568
Beginning balance, shares at Dec. 31, 2010	'	11,155,080	'	'	'
Net income	11,687	'	'	11,687	'
Other comprehensive income	-5,568	'	'	'	-5,568
Stock options exercised, cashless	1	1	'	'	'
Stock options exercised, cashless, shares	'	1,088	'	'	'
Stock-based compensation expense, exclusive of amounts withheld for payroll taxes	1,107	5	1,102	'	'
Stock-based compensation expense, exclusive of amount withheld for payroll taxes, shares	'	59,490	'	'	'
Dividends declared and paid on preferred stock	-3,723	'	'	-3,723	'
Ending balance at Dec. 31, 2011	56,209	1,122	45,685	9,402	'
Ending balance, shares at Dec. 31, 2011	'	11,215,658	'	'	'
Net income	-10,327	'	'	-10,327	'
Other comprehensive income	'	'	'	'	'
Stock-based compensation expense, exclusive of amounts withheld for payroll taxes	1,311	6	1,305	'	'
Stock-based compensation expense, exclusive of amount withheld for payroll taxes, shares	'	63,610	'	'	'
Dividends declared and paid on preferred stock	-3,723	'	-1,585	-2,138	'
Ending balance at Dec. 31, 2012	43,470	1,128	45,405	-3,063	'
Ending balance, shares at Dec. 31, 2012	'	11,279,268	'	'	'
Net income	-13,073	'	'	-13,073	'
Other comprehensive income	'	'	'	'	'
Stock options exercised, cashless, shares	'	'	'	'	'
Stock-based compensation expense, exclusive of amounts withheld for payroll taxes	637	17	620	'	'
Stock-based compensation expense, exclusive of amount withheld for payroll taxes, shares	'	173,205	'	'	'
Dividends declared and paid on preferred stock	-3,723	'	-3,723	'	'
Ending balance at Dec. 31, 2013	$27,311	$1,145	$42,302	($16,136)	'
Ending balance, shares at Dec. 31, 2013	'	11,452,473	'	'	'

Business_Description_and_Summa

Business Description and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Business Description and Summary of Significant Accounting Policies	'
	1	Business Description and Summary of Significant Accounting Policies
	Description of Operations
	Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, production and sale of natural gas and oil, primarily in the Rocky Mountain basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001.
	Principles of Consolidation and Basis of Presentation
	The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream Pipeline LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit. This fee is also eliminated in consolidation.
	The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.
	Certain reclassifications have been made to amounts reported in previous years to conform to the 2013 presentation. Such reclassifications had no effect on net income.
	Cash and Cash Equivalents
	Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value due to the short maturity of these instruments.
	Cash Held in Escrow
	The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at December 31, 2013 and 2012 totaled $283 and $565, respectively.
	Accounts Receivable
	The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2013, 2012 or 2011.
	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 oil and gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.
	Concentration of Market Risk
	The future results of the Company’s operations will be affected by the market prices of natural gas.  Natural gas comprised approximately 98% of our total production for the year ended December 31, 2013 and represented 97% of our reserves as of December 31, 2013.  The market for natural gas in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of gas, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.
	The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from the Company’s third party gas marketing company and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. Collectability is dependent upon the financial wherewithal of each counterparty as well as the general economic conditions of the industry. The receivables are not collateralized.
	Concentration of Credit Risk
	Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. The Company currently uses three counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.
	Revenue Recognition and Gas Balancing
	The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby the working interest owner records revenue based on its share of entitled production, regardless of whether the Company has taken its ownership share of such volumes. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2013 resulted in an imbalance receivable of 115 MMcf, or $327, which is included in accounts receivable, net, on the consolidated statement of operations, and an imbalance payable of 241 MMcf, or $900, which is included in accounts payable and accrued expenses on the consolidated statement of operations.
	Oil and Gas Producing Activities
	The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves in sufficient quantities to render the well economic, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on expected future prices and costs.
	Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred.
	Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is calculated on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds for equipment salvage. The Company has historically based the fourth quarter depletion calculation on the respective year end reserve report and used this methodology in computing the fourth quarter 2013 depletion expense.
	DD&A of oil and gas properties for the years ended December 31, 2013, 2012 and 2011 was $20,560, $19,828 and $18,439, respectively.
	The Company invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.
	The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2013, 2012 and 2011. Amounts do not include costs capitalized and subsequently expensed in the same annual period.
			2013			2012			2011
	Beginning balance at January 1,		$	-		$	4,170		$	-
	Additions to capitalized exploratory well costs pending			-			6,650			16,198
	the determination of proved reserves
	Reclassifications to wells, facilities and equipment			-			(6,390	)		(12,028	)
	based on the determination of proved reserves
	Capitalized exploratory well costs charged to expense			-			(4,430	)		-
	Ending balance at December 31,		$	-		$	-		$	4,170
	Asset Retirement Obligations
	Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties and related production facilities, lines and other equipment used in the field operations.
	The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost, and then depleted over the life of the asset.  The Company utilizes the income valuation technique to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The liability is periodically adjusted to reflect (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense and (4) revisions to estimated future cash flow requirements. For the years ended December 31, 2013, 2012 and 2011, an expense of $276, $188 and $174, respectively, was recorded as accretion expense on the liability and included in production costs on the consolidated statement of operations.
	Impairment of Long-Lived Assets
	The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its oil and gas properties and undeveloped leaseholds annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows. The impairment analysis performed by the Company may utilize Level 3 inputs.
	The Company recorded proved property impairment expense of $4,962, $4,901 and $0 for the years ended December 31, 2013, 2012 and 2011, respectively.  The impairment expense in 2013 and 2012, primarily related to its Niobrara exploration well.  The Company began drilling a well targeting the Niobrara, Dakota and Frontier formations in the fourth quarter of 2011.  Wyoming wildlife regulations prohibit drilling in this well location for approximately seven months of the year, which delayed our well completion and initial production until February 2013.  The Company exceeded its initial capital budget for the well due to challenges experienced during the drilling of the well, and the subsequent decision to complete the well in zones that were not initially planned for production.  The initial production results from the Niobrara formation were encouraging; however, subsequent production decreased significantly.  As a result, for the year ended December 31, 2012, the Company re-evaluated the well’s geology and recorded an initial impairment on the well of $4,430 based on expected future discounted net cash flows from the well.
	In 2013, the Company installed a pump on the well and attempted to regain oil production; however, the Company continues to recover injection fluid that was initially injected into the ground during the fracture stimulation stage of completion. While the well has not generated economically recoverable amounts of oil, the well is currently producing natural gas from the Niobrara formation and the Company is awaiting a permit that will allow it to begin producing natural gas from the Dakota and Frontier formations.  The Company anticipates receipt of this permit during 2014, and, subject to receipt of the permit, expects production from these formations to begin in the third quarter of 2014.  Management continues to evaluate oil production from this well, but due to its limited capital, further work thus far has been cost-prohibitive.  Based on the Company’s production results to date, management has updated it estimate of future net cash flow from this well, and recorded additional impairment expense of $4,812 for the year ended December 31, 2013.  The Company recognized a non-cash charge on undeveloped leaseholds during the years ended December 31, 2013, 2012 and 2011 of $30, $87 and $187, respectively.
	The Company’s pipeline facilities are recorded at cost, which totaled $5,510 as of December 31, 2013. Depreciation is recorded using the straight-line method over a 25 year estimated useful life, and totaled $221 for the year ended December 31, 2013. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2013, and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.
	Corporate and Other Assets
	Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 to 40 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $161, $167 and $186, respectively.
	Major Customers
	The Company had sales to one major unaffiliated gas marketing customer for the years ended December 31, 2013, 2012 and 2011 totaling $26,360, $23,145 and $22,159, respectively. No other single customer accounted for 10% or more of revenues in 2013, 2012 and 2011. Although a substantial portion of the Company’s production is purchased by one customer, the Company does not believe the loss of this customer would have a material adverse effect on the Company’s business as there are other gas marketers serving in the area where the Company operates.
	Industry Segment and Geographic Information
	The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and oil. All of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment. The Company’s transportation and gathering subsidiary provides services exclusively for the company that markets its gas and all of the revenue generated by this subsidiary is primarily related to volumes produced from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to the transportation and gathering subsidiary are presented as separate line items in the accompanying consolidated statement of operations.
	Employee Benefit Plan
	The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimum eligibility requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years ended 2013, 2012 and 2011 were $197, $226 and $221, respectively.
	Income Taxes
	Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.
	Earnings per Share
	Basic earnings per share (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $3,723 ($.5781 per share of preferred stock) for each of the years ended December 31, 2013, 2012 and 2011.
	The following table shows the calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:
			For the year ended December 31,
			2013			2012			2011
	Net income (loss)		$	(13,073	)	$	(10,327	)	$	11,687
	Preferred stock dividends			(3,723	)		(3,723	)		(3,723	)
	Income (loss) attributable to common stock		$	(16,796	)	$	(14,050	)	$	7,964
Weighted average shares:
Weighted average shares - basic			11,332,129			11,250,513			11,191,496
Dilutive effect of stock options outstanding			-			-			19,108
at the end of period
Weighted average shares - fully diluted			11,332,129			11,250,513			11,210,604
Net income (loss) per share:
Basic		$	(1.48	)	$	(1.25	)	$	0.71
Diluted		$	(1.48	)	$	(1.25	)	$	0.71
The following options and stock awards that could be potentially dilutive in future periods were not included in the computation of diluted net income (loss) per share because the effect would have been anti-dilutive for the periods indicated:
		For the years ended December 31,
		2013			2012			2011
Potential common shares			28,612			58,704			48,724
Stock-Based Compensation
The Company measures and recognizes compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Certain awards contain a performance condition, which is taken into account in estimating fair value.
Derivative Financial Instruments
The Company uses derivative instruments, primarily swaps and collars, to hedge risk associated with fluctuating commodity prices. The Company accounts for its derivatives instruments as mark-to-market instruments and are recorded at fair value and included in the consolidated balance sheets as assets or liabilities with changes in fair value recorded in earnings. See Notes 4 and 6 for additional discussion of derivative activities.
Recently Adopted Accounting Pronouncements
In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-01 (“ASU No. 2013-01”), ASU No. 2013-01 clarifies that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASU No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASU No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASU No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

Credit_Facility

Credit Facility	12 Months Ended
	Dec. 31, 2013
Credit Facility	'
	2	Credit Facility
	As of December 31, 2013, the Company had a $150,000 revolving line of credit (“Credit Facility”) in place with a $60,000 borrowing base. Effective January 9, 2014, the borrowing base was reduced from $60,000 to $55,000 as a result of its October 1, 2013 borrowing base redetermination.  The Credit Facility is collateralized by the Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.
	As of December 31, 2013, the balance outstanding of $47,450 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Company’s Niobrara exploration project.
	Borrowings under the Credit Facility bear interest at a daily rate equal to (a) the highest of the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at December 31, 2013, including the impact of our interest rate swaps, was 3.3%. For the years ended December 31, 2013, 2012 and 2011, the Company incurred interest expense on the credit facility of $1,635, $1,275 and $1,070, respectively. Of the total interest incurred, the Company capitalized interest costs of $80, $321 and $155 for the years ended December 31, 2013, 2012 and 2011, respectively.
	Under the Credit Facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of December 31, 2013, the Company was in compliance with all financial and non-financial covenants. If the covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the lenders would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation	'
	3	Asset Retirement Obligation
	The following table reflects a reconciliation of the Company’s asset retirement obligation liability:
		For the year ended December 31,
		2013			2012
	Beginning asset retirement obligation	$	8,494		$	6,300
	Liabilities incurred		368			12
	Liabilities settled		(258	)		(9	)
	Accretion expense		276			188
	Additional liabilities assumed through acquisition		-			2,003
	Revision to estimated cash flows		(460	)		-
	Ending asset retirement obligation	$	8,420		$	8,494

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
	4	Derivative Instruments
	Commodity Contracts
	The Company’s primary market exposure is to adverse fluctuations in the price of natural gas. The Company uses derivative instruments, primarily costless collars and swaps, to manage the price risk associated with its gas production, and the resulting impact on cash flow, net income and earnings per share. The Company does not use derivative instruments for speculative purposes.
	The extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Company’s Board of Directors. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12-month period, and up to 80% of the projected proved developed producing reserves for the 24-month period thereafter.
	The Company accounted for all of its derivative instruments as mark-to-market derivative instruments in 2013 and 2012. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated balance sheets and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of mark-to-market derivatives also are recorded in the price risk management activities line on the consolidated statements of operations.
	In 2011, the Company had one derivative instrument that was accounted for as a cash flow hedge. Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. The last derivative instrument that the Company accounted for under cash flow hedge accounting settled in December 2011.
	On the consolidated statements of cash flows, the cash flows from the derivative instruments are classified as operating activities.
	The terms of the Company’s derivative instruments outstanding at December 31, 2013 are summarized as follows:
	Type of Contract		Remaining				Term		Price					Price Index (1)
			Contractual
			Volume (Mcf)
	Fixed Price Swap			1,825,000			01/14-12/14		$	4.27				NYMEX
	Costless Collar			1,800,000			01/14-12/14		$	4		floor		NYMEX
									$	4.5		ceiling
	Fixed Price Swap			1,800,000			01/14-12/14		$	4.2				NYMEX
	Fixed Price Swap			540,000			01/14-12/14		$	4.17				NYMEX
	Fixed Price Swap			3,000,000			01/15-12/15		$	4.28				NYMEX
	Fixed Price Swap			3,600,000			01/15-12/15		$	4.15				NYMEX
	Fixed Price Swap			1,830,000			01/16-12/16		$	4.07				NYMEX
	Total			14,395,000
	Interest Rate Swap
	The Company has a $30 million fixed rate swap in place to manage the risk associated with the floating interest rate on its credit facility. Refer to Note 4 for a detailed breakout of the contract terms. Under the interest rate swap terms, the Company swapped its floating LIBOR interest rate for a fixed LIBOR interest rate. These contracts were not designated as fair value hedges or cash flow hedges and are recorded at fair value on the consolidated balance sheets. Changes in fair value, both realized and unrealized, are recognized in interest expense, net on the consolidated statements of operations. On the consolidated statements of cash flows, the cash flows from the interest rate swap are classified as operating activities.
	As of December 31, 2013, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on the Credit Facility:
			Contractual										Effective
	Type of Contract		Amount				Term		Rate (LIBOR)				Interest Rate (1)
	Interest Rate Swap		$	30,000			12/31/12-9/30/16			1.05%				3.55%
	Impact of Derivatives on the Balance Sheet and Consolidated Statement of Operations
	The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of December 31, 2013 and December 31, 2012, presented gross of any master netting arrangements:
						As of December 31,
	Balance Sheet Location					2013				2012
	Assets
	Commodity derivatives			Assets from price risk management - current		$	218			$	6,742
				Assets from price risk management - long term			402				682
	Total derivative assets					$	620			$	7,424
	Liabilities
	Commodity derivatives			Liabilities from price risk management - current			(13	)			-
				Liabilities from price risk management -long term			(97	)			-
	Interest rate swap			Other current liabilities			(222	)			(200	)
				Other long term liabilities			(90	)			(370	)
	Total derivative liabilities					$	(422	)		$	(570	)
	The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:
			Amount of Gain Recognized in OCI
			on Derivatives for the Year Ended December 31,
			2013				2012		2011
	Commodity contracts		$	-			$                           -		$                        997
	Location of Gain Reclassified
	from AOCI  into		Amount of Gain Reclassified from
	Income (effective portion)		for the Year Ended December 31,
			2013				2012				2011
	Oil and gas sales		$	-			$	-			$	9,592
		Year Ended December 31,
			2013				2012				2011
	Location of Gain Recognized in Income (Ineffective) Portion
	and Amount Excluded from Effectiveness Testing		$	-		1	$	-		1	$	-
	1 Not applicable as the Company did not have any cash flow hedges in the years ended December 31, 2013 and 2012.
	The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:
			Amount of Gain Recognized in Income on Derivatives for the
			Year Ended December 31,
			2013				2012				2011
	Unrealized gain (loss) on commodity contracts 2		$	(6,915	)		$	(7,410	)		$	13,807
	Realized gain on commodity contracts 2			6,185				12,349				933
	Unrealized gain (loss) on interest rate swap 3			258				(523	)			(47	)
	Realized loss on interest rate swap 3			(265	)			(111	)			(52	)
Total activity for derivatives not designated as hedging instruments		$	(737	)		$	4,305			$	14,641
2 Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(730), $4,939 and $14,740, for the years ended December 31, 2013, 2012 and 2011, respectively.
3 Included in interest expense, net on the statements of operations.
Refer to Note 6 for additional information regarding the valuation of the Company’s derivative instruments.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
	5	Income Taxes
	The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 were:
			As of December 31,
			2013				2012
	Deferred tax assets:
	Net operating loss carry-forward		$	20,892			$	17,196
	Asset retirement obligation			3,022				2,980
	Stock-based compensation			963				940
	Accrued compensation			25				28
	Net gas imbalance			134				139
	Other			64				63
				25,100				21,346
	Deferred tax liabilities:
	Derivative instruments			(65	)			(2,393	)
	Net basis difference in oil and gas properties			(26,271	)			(26,849	)
	Net deferred tax liability		$	(1,236	)		$	(7,896	)
	In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income. At December 31, 2013, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $59.0 million, which will expire beginning in 2021.
	The following table shows the reconciliation of the Company’s effective tax rate to the expected federal tax rate for the years ended December 31, 2013 and 2012:
		For the year ended December 31,
		2013				2012
	Expected federal tax rate		35	%			35	%
	Effect of permanent differences		-0.3	%			-0.78	%
	State tax rate		0.87	%			0.09	%
	Other		-1.82	%			0.1	%
	Effective tax rate		33.75	%			34.41	%
	In accordance with the FASB’s Accounting Standards Codification (“ASC”) 740, Income Taxes, tax effects from any uncertain tax positions are recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has not recorded any liabilities, or interest and penalties, as of December 31, 2013 related to uncertain tax positions.
	The Company files income tax returns in the U.S. and various state jurisdictions. The Company are currently has no federal or state income tax examinations underway for any of these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2010 and for state and local tax authorities for years before 2009.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements	'
	6	Fair Value Measurements
	Assets and Liabilities Measured on a Recurring Basis
	The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s Credit Facility also approximates fair value as it bears interest at a floating rate.
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The FASB has established a three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs in the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:
	Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.
	Level 2 - Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and model-derived valuations whose inputs or significant value drivers are observable.
	Level 3 - Unobservable inputs that reflect the Company’s own assumptions.
	The following tables provide a summary of assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012:
		Fair Value Measurements for the year ended December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets
	Derivative instruments -	$	-	$	607	$	-	$	607
	Commodity forward contracts
	Total assets as fair value	$	-	$	607	$	-	$	607
	Liabilities
	Derivative instruments -	$	-	$	97	$	-	$	97
	Commodity forward contracts
	Derivative instruments -		-		312		-		312
	Interest rate swap
	Total liabilities as fair value	$	-	$	409	$	-	$	409
		Fair Value Measurements for the year ended December 31, 2012
		Level 1		Level 2		Level 3		Total
	Assets
	Derivative instruments -	$	-	$	7,424	$	-	$	7,424
	Commodity forward contracts
	Total assets as fair value	$	-	$	7,424	$	-	$	7,424
	Liabilities
	Derivative instruments -	$	-	$	570	$	-	$	570
	Interest rate swap
	Total liabilities as fair value	$	-	$	570	$	-	$	570
	The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the year ended December 31, 2013.
	The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:
	Derivative instruments
	The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, market-corroborated inputs, such as NYMEX forward-strip pricing, the credit rating of each counterparty, and the Company’s own credit rating.
	In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.
	As of December 31, 2013, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
	Assets and Liabilities Measured on a Non-recurring Basis
	The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3. Please refer to Note 1 for additional information regarding the Company’s impairment analysis for the year ended December 31, 2013.
	The following table provides a summary as of December 31, 2013 of assets measured at fair value on a nonrecurring basis:
		Level 1		Level 2		Level 3		Total
	Assets
	Oil and gas properties -	$	-	$	-	$	2,916	$	2,916
	Niobrara well
	Total assets as fair value	$	-	$	-	$	2,916	$	2,916

Preferred_Stock_and_Stockholde

Preferred Stock and Stockholder's Equity	12 Months Ended
	Dec. 31, 2013
Preferred Stock and Stockholder's Equity	'
	7	Preferred Stock and Stockholder’s Equity
	In 2007, the Company’s stockholders approved an amendment to the Company’s Articles of Incorporation to provide for the issuance of 10,000,000 shares of preferred stock, and the Company subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) at a price of $25.00 per share.
	Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Company’s Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions except, under certain circumstances, upon a change of ownership or control. The Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date.
	The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to the change of control redemption provision applicable to such shares. Following a change of ownership or control of the Company by a person or entity in which the common stock of the Company is no longer traded on a national exchange, the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control occurred for cash. In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of the Company’s common stock.
	Holders of the Series A Preferred Stock generally have no voting rights. However, if cash dividends on any outstanding Series A Preferred Stock are in arrears for any six consecutive or non-consecutive quarterly dividend periods, or if the Company fails to maintain a national market listing, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on the Company’s Board of Directors in addition to those directors then serving on the Board until such time as the national market listing is obtained or the dividend arrearage is eliminated.

Compensation_Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2013
Compensation Plans	'
	8	Compensation Plans
	The Company has outstanding stock options issued to employees under various stock option plans, approved by the Company’s stockholders (collectively the “Plans”). Options granted under the Plans have been granted with an exercise price equal to the market price of the Company’s common stock on the date of grant, vest annually over various periods from two to five years of continuous service, and expire over various periods up to ten years from the date of grant. As of December 31, 2013, there were 24,971 and 39,998 options available for grant under the 2002 and 2003 Stock Option Plans, respectively.
	The Company’s stockholders have also approved the 2007 Stock Incentive Plan (“2007 Plan”) and the 2010 Stock Incentive Plan, (“2010 Plan”), which allow both stock options and stock awards to be granted to the Company’s employees, directors, consultants, and other persons designated by the Compensation Committee of the Board of Directors. In 2008, the Company began granting stock awards and stock options under these plans. These awards vest annually over various periods of up to five years of continuous service. As of December 31, 2013, there were 424,409 and 388,508 shares available for grant under the 2007 and 2010 Plans, respectively.
	The Company accounts for its stock compensation in accordance with the provisions of ASC 718, Compensation – Stock Compensation , which requires the measurement and recognition of compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. During the years ended December 31, 2013, 2012 and 2011, total stock-based compensation expense for equity-classified awards, was $744, $1,341 and $1,153, respectively, and is reflected in general and administrative expense in the consolidated statements of operations.
	Stock Options
	The Company uses the Black-Scholes valuation model to determine the fair value of each option award. Expected volatilities are based on the historical volatility of the Company’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.
	The assumptions used in estimating the fair value of stock-options granted were:
		For the year ended December 31,
		2013 (1)		2012 (1)		2011
	Weighted-average volatility	n/a		n/a			61%
	Expected dividends	n/a		n/a			0.00%
	Expected term (in years)	n/a		n/a		4.75
	Risk-free rate	n/a		n/a			2.02%
	Expected forfeiture rate	n/a		n/a			8.00%
	-1	The Company did not grant any stock options in 2013 and 2012.
	Summary of option activity during the year ended December 31, 2013:
			Shares				Weighted-		Weighted-		Aggregate
							Average		Average		Intrinsic
							Exercise		Remaining		Value
							Price		Contractual
									Term (in years)
	Options:
	Outstanding at January 1, 2013			419,350			$	11.06		2.9
	Granted		-
	Exercised		-
	Cancelled/expired			(142,496	)		$	10.81
	Outstanding at December 31, 2013			276,854			$	11.19		2.7	$	-
	Exercisable at December 31, 2013			250,143			$	11.81		2.7	$	-
	No stock options were granted in 2013 or 2012. The weighted average grant date fair value price per share of options granted during the year ended December 31, 2011 was $2.65. No stock options exercised in 2013 and 2012. During the year ended December 31, 2011, the total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised was $9. The Company issues new shares from its reserve upon exercise. As of December 31, 2013, 2012 and 2011, the intrinsic value of options vested and exercisable was $0, $0 and $89, respectively.
	Stock options outstanding and currently exercisable at December 31, 2013 were as follows:
											Options Exercisable
	Range of Exercise		Number of				Options Outstanding		Weighted		Number of Options Exercisable		Weighted
	Prices per Share		Options				Weighted Average		Average				Average
			Outstanding				Remaining		Exercise Price				Exercise Price
							Contractual Life		per Share				per Share
							(in years)
	$4.33 - $5.10			68,503				3.3	$	4.74		47,191	$	4.7
	$6.78- $7.79			42,000				2.2	$	7.49		36,600	$	7.44
	$14.00 - $16.31			166,351				2.6	$	14.79		166,352	$	14.79
				276,854				2.7	$	11.19		250,143	$	11.81
	As of December 31, 2013, there was $21 of total unrecognized stock-based compensation expense related to stock options to be recognized over a weighted-average period of 1.2 years.
	Stock Awards
	The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognize the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate, if applicable, and recognizes the compensation costs for only those shares expected to vest. The forfeiture rates are based on historical experience, while also considering the duration of the vesting term of the award.
	Nonvested stock awards as of December 31, 2013 and changes for the year ended December 31, 2013 were as follows:
			Shares				Weighted-
							Average
							Grant Date
							Fair Value
	Stock Awards:
	Outstanding at January 1, 2013			533,981			$	6.33
	Granted			90,715			$	4.01
	Vested			(215,198	)		$	5.72
	Forfeited/returned			(368,583	)		$	6.36
	Nonvested at December 31, 2013			40,915			$	4.12
	As of December 31, 2013, there was $132 of unrecognized stock-based compensation expense related to nonvested stock awards. This cost is expected to be recognized over a weighted-average period of 0.7 years.  The intrinsic value of restricted stock awards vested was $642, $372 and $457 for the years ended December 31, 2013, 2012 and 2011, respectively.
	Long-Term Incentive Plan
	In the fourth quarter of 2011, the Company adopted a Long-Term Incentive Plan (“LTIP”), under which the executive officers of the Company could earn shares for both continuous employment (one-third of the total shares) and through increases in the Company’s adjusted net asset value, as defined in the LTIP (two-thirds of the total shares). On December 31, 2013, 135,421 shares vested due to the continuous employment of its executive officers. The Company did not meet the minimum performance objectives as determined by the LTIP, and therefore no performance-based shares vested at December 31, 2013. The total compensation expense recorded by the Company related to the LTIP was $317, $462 and $161 for years ended December 31, 2013, 2012 and 2011, respectively. The nonvested stock awards table above includes the activity related to the Company’s LTIP.
	On January 1, 2014, the Company granted 181,903 shares to the certain of its executive management.  The shares will vest upon a change of control that is consummated and becomes effective on or before December 31, 2014. The shares issued under the award agreements will be subject to additional forfeiture restrictions, including the requirement that the executive’s employment has not terminated prior to the date of a change in control.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies	'
	9	Commitments and Contingencies
	Operating Lease Commitments
	The Company has entered into an operating lease through November 2015 for approximately 7,470 square feet of office space in Denver, Colorado. The Company also maintains operating leases various pieces of office equipment in both the Casper and Denver offices. The total annual minimum lease payments for the next five years and thereafter are:
	Year ending December 31,		Lease
			Commitments
	2014			139
	2015			132
	2016			-
	2017 and thereafter			-
	Total		$	271
	The Company also leases certain compressor equipment in the Catalina Unit on a short-term basis of 12 months or less.
	Total expense from operating leases totaled $2,634, $2,888 and $2,049 in 2013, 2012 and 2011, respectively.
	Litigation and Contingencies
	From time to time, the Company is involved in various legal proceedings, which are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

Acquisition_of_Atlantic_Rim_Wo

Acquisition of Atlantic Rim Working Interests	12 Months Ended
	Dec. 31, 2013
Acquisition of Atlantic Rim Working Interests	'
	10	Acquisition of Atlantic Rim Working Interests
	On October 9, 2012, the Company exercised its preferential right to acquire additional working interest in the Catalina Unit and Spyglass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”). The Company had previously signed an agreement with Anadarko to acquire 100% of Anadarko’s working interest in the Spyglass Hill and Catalina Units’ acreage; however, the joint operating agreements governing the Catalina and Spyglass Hill Units give preferential purchase rights to the other working interest owners in the event a working interest owner sells its assets. The other major owner in these units exercised its preferential right, reducing the amount of additional working interest acquired by the Company. The purchase expanded the Company’s presence in one of its core development areas. The effective date of this transaction was August 1, 2012.
	The following table summarizes the working interest acquired as a result of the transaction, and the Company’s post-transaction total ownership in each of the participating areas.
	Participating Area		Working Interest Acquired			Working Interest Following Purchase
	Catalina			14.33	%		85.53	%
	Sun Dog			8.73	%		28.59	%
	Doty Mountain			8.73	%		26.73	%
	The 2012 acquisition of working interest was accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price of $4,874 is allocated to the assets acquired and liabilities assumed based on their estimated fair values. The final purchase price allocation was as follows:
	Amounts recognized for final fair value of assets acquired and liabilities assumed:
	Developed properties		$	6,877
	Asset retirement obligation		$	(2,003	)
	Total fair value of oil and gas properties acquired		$	4,874
	The Company utilized the income approach to estimate the fair value of the properties and used discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows: (1) estimated recovery of natural gas and oil as prepared by a third party engineering firm; (2) estimate of future commodity prices as of the acquisition date; (3) estimated future production rates and decline curves; and (4) estimated timing and amounts of future operating and development costs. The Company then applied a market-based discount rate to the future net cash flows that took in to consideration factors such as non-operatorship in the Spyglass Hill Unit, the unique operating agreements in this area and the low-pricing environment for dry Rockies natural gas. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

Supplemental_Information_on_Oi

Supplemental Information on Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Gas Producing Activities	'
	11	Supplemental Information on Oil and Gas Producing Activities
	Capitalized Costs Relating to Oil and Gas Producing Activities
	The aggregate amount of capitalized costs relating to oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011 were:
		As of December 31,
		2013			2012			2011
	Developed properties	$	238,332		$	225,382		$	209,774
	Wells in progress		2,342			10,963			8,182
	Undeveloped properties		2,705			2,734			2,921
			243,379			239,079			220,877
	Accumulated depletion and amortization		(127,372	)		(106,811	)		(88,639	)
	Net capitalized costs	$	116,007		$	132,268		$	132,238
	Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities
	Costs incurred in property acquisitions, exploration, and development activities for the years ended December 31, 2013, 2012 and 2011 were:
		For the year ended December 31,
		2013			2012			2011
	Acquisitions
	Unproved properties	$	-		$	7		$	266
	Proved properties		-			4,874		-
	Exploration		-			7,279			16,311
	Development		9,622			11,166			9,203
	Total	$	9,622		$	23,326		$	25,780
	Results of Operations from Oil and Gas Producing Activities
	The table below shows the results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011. All production is from within the continental United States.
		For the year ended December 31,
		2013			2012			2011
	Operating revenues (1)	$	37,969		$	38,923		$	45,093
	Costs and expenses:
	Production		17,041			15,299			15,412
	Exploration		181			696			273
	Depletion, amortization and impairment		25,372			24,159			18,439
	Total costs and expenses		42,594			40,154			34,124
	Income before income taxes		(4,625	)		(1,231	)		10,969
	Income tax expense (benefit)		(1,561	)		(422	)		3,863
	Results of operations	$	(3,064	)	$	(809	)	$	7,106
	-1	Operating revenues are comprised of the oil and gas sales from the consolidated statement of operations, plus settlements on the Company’s derivative instruments during the period included in price risk management activities on the consolidated statement of operations, totaling $6,185, $12,349 and $933, for the years ended December 31, 2013, 2012 and 2011, respectively.
	Oil and Gas Reserves (Unaudited)
	The reserves at December 31, 2013, 2012 and 2011 presented below were reviewed by the independent engineering firm, Netherland, Sewell & Associates, Inc. All reserves are located within the continental United States. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors.
	Estimated net quantities of proved developed reserves of oil and gas for the years ended December 31, 2013, 2012 and 2011 are:
		For the year ended December 31,
		2013						2012						2011
		Oil			Gas			Oil			Gas			Oil			Gas
		(Bbl)			(Mcf)			(Bbl)			(Mcf)			(Bbl)			(Mcf)
	Beginning of year		256,144			76,591,597			450,201			133,903,563			381,251			112,768,514
	Revisions of estimates		73,729			3,798,009			(164,126	)		(60,809,714	)		2,306			(834,305	)
	Extensions and discoveries		13,187			1,451,355			1,675			405,922			94,735			31,144,009
	Purchases of reserves	-			-			-			-			-			-
	Production		(29,082	)		(9,037,310	)		(31,606	)		(10,325,205	)		(28,091	)		(9,174,655	)
	End of year		313,978			72,803,651			256,144			76,591,597			450,201			133,903,563
	Proved developed reserves		207,999			58,588,355			207,881			71,146,164			245,124			80,121,740
	Percentage of proved developed reserves		66	%		80	%		81	%		93	%		54	%		60	%
	As of December 31, 2013, the Company had estimated proved reserves of 72.8 Bcf of natural gas and 314 MBbl of oil, or a total of 74.7 Bcfe.
	As of December 31, 2013, 80% of the proved gas reserves and 66% of the proved oil reserves were in producing status.
	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
	The following information has been developed utilizing procedures prescribed by ASC 932 Extractive Activities – Oil and Gas, and is based on natural gas and oil reserves and production volumes estimated by the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative or realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
	The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will likely differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in these calculations; (3) selection of a 10% discount rate, as required under the accounting codification, is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
	Under the Standardized Measure, future cash inflows were estimated by applying the 12-month average pricing of oil and gas relating to the Company’s proved reserves to the year-end quantities of those reserves. Future cash inflows were reduced by estimated future development and production costs based upon year-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying year-end statutory rates to future pretax net cash flows and the utilization of net operating loss carry-forwards.
	Management does not rely solely upon the following information to make investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable, as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
	Information with respect to the Company’s Standardized Measure is as follows:
		As of December 31,
		2013			2012			2011
	Future cash inflows	$	262,889		$	192,417		$	537,682
	Future production costs		(110,858	)		(92,868	)		(199,369	)
	Future development costs		(8,161	)		(6,502	)		(43,569	)
Future income taxes		(13,532	)	-				(64,103	)
Future net cash flows		130,338			93,047			230,641
10% annual discount		(55,034	)		(34,822	)		(109,964	)
Standardized Measure	$	75,304		$	58,225		$	120,677
Principal changes in the Standardized Measure for the years ended December 31, 2013, 2012 and 2011 were as follows:
	2013			2012			2011
Standard measure, as of January 1,	$	58,225		$	120,677		$	114,944
Sales of oil and gas produced, net of production costs		(14,744	)		(24,586	)		(28,748	)
Extensions and discoveries		1,776			343			28,130
Net change in prices and production costs related to future production		31,546			(95,294	)		(1,363	)
Development costs incurred during the year		381			4,231			6,014
Changes in estimated future development costs		(2,646	)		23,945			(1,145	)
Purchases of reserves in place		-			9,026		-
Revisions of quantity estimates		2,936			(47,810	)		(932	)
Accretion of discount		5,823			14,022			12,815
Net change in income taxes		(2,879	)		33,512			(4,791	)
Changes in timing and other  (1)		(5,114	)		20,159			(4,247	)
Aggregate change		17,079			(62,452	)		5,733
Standardized measure, as of December 31,	$	75,304		$	58,225		$	120,677
-1	Due to the decrease in pricing for the year ended December 31, 2012, the economic life of the Company’s wells was shortened, causing the total discount taken on its future net cash flows to decrease.  The impact is included in the above table as Changes in timing and other.

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data (Unaudited)	'
	12	Quarterly Financial Data (Unaudited)
	The following table contains a summary of the unaudited financial data for each quarter for the years ended December 31, 2013 and 2012 (in thousands except per share data):
		Fourth			Third			Second			First
		Quarter			Quarter			Quarter			Quarter
	Year ended December 31, 2013
	Oil and gas sales	$	8,150		$	7,599		$	8,502		$	7,533
	Income (loss) from operations	$	(9,235	)	$	(2,310	)	$	696		$	(7,577	)
	Net income (loss)	$	(6,406	)	$	(1,852	)	$	361		$	(5,176	)
	Net loss attributable to common stock	$	(7,337	)	$	(2,782	)	$	(570	)	$	(6,107	)
	Basic net loss per common share	$	(0.64	)	$	(0.25	)	$	(0.05	)	$	(0.54	)
	Diluted net loss per common share	$	(0.64	)	$	(0.25	)	$	(0.05	)	$	(0.54	)
	Year ended December 31, 2012
	Oil and gas sales	$	8,831		$	6,498		$	5,214		$	6,031
	Income (loss) from operations	$	(4,199	)	$	(5,207	)	$	(5,484	)	$	755
	Net income (loss)	$	(3,067	)	$	(3,568	)	$	(4,020	)	$	328
	Net loss attributable to common stock	$	(3,998	)	$	(4,498	)	$	(4,951	)	$	(603	)
	Basic net loss per common share	$	(0.36	)	$	(0.40	)	$	(0.44	)	$	(0.05	)
	Diluted net loss per common share	$	(0.36	)	$	(0.40	)	$	(0.44	)	$	(0.05	)

Business_Description_and_Summa1

Business Description and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Description of Operations	'
	Description of Operations
	Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, production and sale of natural gas and oil, primarily in the Rocky Mountain basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001.
Principles of Consolidation and Basis of Presentation	'
	Principles of Consolidation and Basis of Presentation
	The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream Pipeline LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit. This fee is also eliminated in consolidation.
	The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.
	Certain reclassifications have been made to amounts reported in previous years to conform to the 2013 presentation. Such reclassifications had no effect on net income.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value due to the short maturity of these instruments.
Cash Held in Escrow	'
	Cash Held in Escrow
	The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at December 31, 2013 and 2012 totaled $283 and $565, respectively.
Accounts Receivable	'
	Accounts Receivable
	The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2013, 2012 or 2011.
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 oil and gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.
Concentration of Credit Risk	'
	Concentration of Credit Risk
	Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. The Company currently uses three counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.
Revenue Recognition and Gas Balancing	'
	Revenue Recognition and Gas Balancing
	The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby the working interest owner records revenue based on its share of entitled production, regardless of whether the Company has taken its ownership share of such volumes. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2013 resulted in an imbalance receivable of 115 MMcf, or $327, which is included in accounts receivable, net, on the consolidated statement of operations, and an imbalance payable of 241 MMcf, or $900, which is included in accounts payable and accrued expenses on the consolidated statement of operations.
Oil and Gas Producing Activities	'
	Oil and Gas Producing Activities
	The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves in sufficient quantities to render the well economic, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on expected future prices and costs.
	Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred.
	Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is calculated on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds for equipment salvage. The Company has historically based the fourth quarter depletion calculation on the respective year end reserve report and used this methodology in computing the fourth quarter 2013 depletion expense.
	DD&A of oil and gas properties for the years ended December 31, 2013, 2012 and 2011 was $20,560, $19,828 and $18,439, respectively.
	The Company invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.
	The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2013, 2012 and 2011. Amounts do not include costs capitalized and subsequently expensed in the same annual period.
		2013			2012			2011
	Beginning balance at January 1,	$	-		$	4,170		$	-
	Additions to capitalized exploratory well costs pending		-			6,650			16,198
	the determination of proved reserves
	Reclassifications to wells, facilities and equipment		-			(6,390	)		(12,028	)
	based on the determination of proved reserves
	Capitalized exploratory well costs charged to expense		-			(4,430	)		-
	Ending balance at December 31,	$	-		$	-		$	4,170
Asset Retirement Obligations	'
	Asset Retirement Obligations
	Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties and related production facilities, lines and other equipment used in the field operations.
	The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost, and then depleted over the life of the asset.  The Company utilizes the income valuation technique to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The liability is periodically adjusted to reflect (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense and (4) revisions to estimated future cash flow requirements. For the years ended December 31, 2013, 2012 and 2011, an expense of $276, $188 and $174, respectively, was recorded as accretion expense on the liability and included in production costs on the consolidated statement of operations.
Impairment of Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its oil and gas properties and undeveloped leaseholds annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows. The impairment analysis performed by the Company may utilize Level 3 inputs.
	The Company recorded proved property impairment expense of $4,962, $4,901 and $0 for the years ended December 31, 2013, 2012 and 2011, respectively.  The impairment expense in 2013 and 2012, primarily related to its Niobrara exploration well.  The Company began drilling a well targeting the Niobrara, Dakota and Frontier formations in the fourth quarter of 2011.  Wyoming wildlife regulations prohibit drilling in this well location for approximately seven months of the year, which delayed our well completion and initial production until February 2013.  The Company exceeded its initial capital budget for the well due to challenges experienced during the drilling of the well, and the subsequent decision to complete the well in zones that were not initially planned for production.  The initial production results from the Niobrara formation were encouraging; however, subsequent production decreased significantly.  As a result, for the year ended December 31, 2012, the Company re-evaluated the well’s geology and recorded an initial impairment on the well of $4,430 based on expected future discounted net cash flows from the well.
	In 2013, the Company installed a pump on the well and attempted to regain oil production; however, the Company continues to recover injection fluid that was initially injected into the ground during the fracture stimulation stage of completion. While the well has not generated economically recoverable amounts of oil, the well is currently producing natural gas from the Niobrara formation and the Company is awaiting a permit that will allow it to begin producing natural gas from the Dakota and Frontier formations.  The Company anticipates receipt of this permit during 2014, and, subject to receipt of the permit, expects production from these formations to begin in the third quarter of 2014.  Management continues to evaluate oil production from this well, but due to its limited capital, further work thus far has been cost-prohibitive.  Based on the Company’s production results to date, management has updated it estimate of future net cash flow from this well, and recorded additional impairment expense of $4,812 for the year ended December 31, 2013.  The Company recognized a non-cash charge on undeveloped leaseholds during the years ended December 31, 2013, 2012 and 2011 of $30, $87 and $187, respectively.
	The Company’s pipeline facilities are recorded at cost, which totaled $5,510 as of December 31, 2013. Depreciation is recorded using the straight-line method over a 25 year estimated useful life, and totaled $221 for the year ended December 31, 2013. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2013, and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.
Corporate and Other Assets	'
	Corporate and Other Assets
	Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 to 40 years for office facilities, 3 to 10 years for office equipment, and 7 years for vehicles. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $161, $167 and $186, respectively.
Industry Segment and Geographic Information	'
	Industry Segment and Geographic Information
	The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and oil. All of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment. The Company’s transportation and gathering subsidiary provides services exclusively for the company that markets its gas and all of the revenue generated by this subsidiary is primarily related to volumes produced from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to the transportation and gathering subsidiary are presented as separate line items in the accompanying consolidated statement of operations.
Employee Benefit Plan	'
	Employee Benefit Plan
	The Company maintains a Simplified Employee Pension Plan covering substantially all employees meeting minimum eligibility requirements. Employer contributions are determined solely at management’s discretion. Employer contributions for years ended 2013, 2012 and 2011 were $197, $226 and $221, respectively.
Income Taxes	'
	Income Taxes
	Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.
Earnings per Share	'
	Earnings per Share
	Basic earnings per share (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $3,723 ($.5781 per share of preferred stock) for each of the years ended December 31, 2013, 2012 and 2011.
	The following table shows the calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:
		For the year ended December 31,
		2013			2012			2011
	Net income (loss)	$	(13,073	)	$	(10,327	)	$	11,687
	Preferred stock dividends		(3,723	)		(3,723	)		(3,723	)
	Income (loss) attributable to common stock	$	(16,796	)	$	(14,050	)	$	7,964
	Weighted average shares:
	Weighted average shares - basic		11,332,129			11,250,513			11,191,496
	Dilutive effect of stock options outstanding		-			-			19,108
	at the end of period
	Weighted average shares - fully diluted		11,332,129			11,250,513			11,210,604
	Net income (loss) per share:
	Basic	$	(1.48	)	$	(1.25	)	$	0.71
	Diluted	$	(1.48	)	$	(1.25	)	$	0.71
	The following options and stock awards that could be potentially dilutive in future periods were not included in the computation of diluted net income (loss) per share because the effect would have been anti-dilutive for the periods indicated:
		For the years ended December 31,
		2013			2012			2011
	Potential common shares		28,612			58,704			48,724
Stock-Based Compensation	'
	Stock-Based Compensation
	The Company measures and recognizes compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Certain awards contain a performance condition, which is taken into account in estimating fair value.
Derivative Financial Instruments	'
	Derivative Financial Instruments
	The Company uses derivative instruments, primarily swaps and collars, to hedge risk associated with fluctuating commodity prices. The Company accounts for its derivatives instruments as mark-to-market instruments and are recorded at fair value and included in the consolidated balance sheets as assets or liabilities with changes in fair value recorded in earnings. See Notes 4 and 6 for additional discussion of derivative activities.
Recently Adopted Accounting Pronouncements	'
	Recently Adopted Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-01 (“ASU No. 2013-01”), ASU No. 2013-01 clarifies that the scope of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASU No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASU No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASU No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

Business_Description_and_Summa2

Business Description and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Net changes in capitalized exploratory well costs	'
	The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2013, 2012 and 2011. Amounts do not include costs capitalized and subsequently expensed in the same annual period.
		2013			2012			2011
	Beginning balance at January 1,	$	-		$	4,170		$	-
	Additions to capitalized exploratory well costs pending		-			6,650			16,198
	the determination of proved reserves
	Reclassifications to wells, facilities and equipment		-			(6,390	)		(12,028	)
	based on the determination of proved reserves
	Capitalized exploratory well costs charged to expense		-			(4,430	)		-
	Ending balance at December 31,	$	-		$	-		$	4,170
Calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock	'
	The following table shows the calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:
		For the year ended December 31,
		2013			2012			2011
	Net income (loss)	$	(13,073	)	$	(10,327	)	$	11,687
	Preferred stock dividends		(3,723	)		(3,723	)		(3,723	)
	Income (loss) attributable to common stock	$	(16,796	)	$	(14,050	)	$	7,964
	Weighted average shares:
	Weighted average shares - basic		11,332,129			11,250,513			11,191,496
	Dilutive effect of stock options outstanding		-			-			19,108
	at the end of period
	Weighted average shares - fully diluted		11,332,129			11,250,513			11,210,604
	Net income (loss) per share:
	Basic	$	(1.48	)	$	(1.25	)	$	0.71
	Diluted	$	(1.48	)	$	(1.25	)	$	0.71
Effect of anti-dilutive shares	'
	The following options and stock awards that could be potentially dilutive in future periods were not included in the computation of diluted net income (loss) per share because the effect would have been anti-dilutive for the periods indicated:
		For the years ended December 31,
		2013			2012			2011
	Potential common shares		28,612			58,704			48,724

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2013
Reconciliation of Asset Retirement Obligation Liability	'
	The following table reflects a reconciliation of the Company’s asset retirement obligation liability:
		For the year ended December 31,
		2013			2012
	Beginning asset retirement obligation	$	8,494		$	6,300
	Liabilities incurred		368			12
	Liabilities settled		(258	)		(9	)
	Accretion expense		276			188
	Additional liabilities assumed through acquisition		-			2,003
	Revision to estimated cash flows		(460	)		-
	Ending asset retirement obligation	$	8,420		$	8,494

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Commodity volumes under derivative contracts	'
	The terms of the Company’s derivative instruments outstanding at December 31, 2013 are summarized as follows:
	Type of Contract		Remaining				Term		Price					Price Index (1)
			Contractual
			Volume (Mcf)
	Fixed Price Swap			1,825,000			01/14-12/14		$	4.27				NYMEX
	Costless Collar			1,800,000			01/14-12/14		$	4		floor		NYMEX
									$	4.5		ceiling
	Fixed Price Swap			1,800,000			01/14-12/14		$	4.2				NYMEX
	Fixed Price Swap			540,000			01/14-12/14		$	4.17				NYMEX
	Fixed Price Swap			3,000,000			01/15-12/15		$	4.28				NYMEX
	Fixed Price Swap			3,600,000			01/15-12/15		$	4.15				NYMEX
	Fixed Price Swap			1,830,000			01/16-12/16		$	4.07				NYMEX
	Total			14,395,000
Summary of Interest rate swaps with a third party	'
	As of December 31, 2013, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on the Credit Facility:
			Contractual										Effective
	Type of Contract		Amount				Term		Rate (LIBOR)				Interest Rate (1)
	Interest Rate Swap		$	30,000			12/31/12-9/30/16			1.05%				3.55%
Summary of derivatives on consolidated balance sheet	'
	The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of December 31, 2013 and December 31, 2012, presented gross of any master netting arrangements:
						As of December 31,
	Balance Sheet Location					2013				2012
	Assets
	Commodity derivatives			Assets from price risk management - current		$	218			$	6,742
				Assets from price risk management - long term			402				682
	Total derivative assets					$	620			$	7,424
	Liabilities
	Commodity derivatives			Liabilities from price risk management - current			(13	)			-
				Liabilities from price risk management -long term			(97	)			-
	Interest rate swap			Other current liabilities			(222	)			(200	)
				Other long term liabilities			(90	)			(370	)
	Total derivative liabilities					$	(422	)		$	(570	)
Before-tax effect of derivative instruments in cash flow hedging relationships on consolidated statements of operations	'
	The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:
			Amount of Gain Recognized in OCI
			on Derivatives for the Year Ended December 31,
			2013				2012		2011
	Commodity contracts		$	-			$                           -		$                        997
	Location of Gain Reclassified
	from AOCI  into		Amount of Gain Reclassified from
	Income (effective portion)		for the Year Ended December 31,
			2013				2012				2011
	Oil and gas sales		$	-			$	-			$	9,592
		Year Ended December 31,
			2013				2012				2011
	Location of Gain Recognized in Income (Ineffective) Portion
	and Amount Excluded from Effectiveness Testing		$	-		1	$	-		1	$	-
	1 Not applicable as the Company did not have any cash flow hedges in the years ended December 31, 2013 and 2012.
Before-tax effect of derivative instruments not designated as hedging instruments on consolidated statements of operations	'
	The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the years ended December 31, 2013, 2012 and 2011 was as follows:
			Amount of Gain Recognized in Income on Derivatives for the
			Year Ended December 31,
			2013				2012				2011
	Unrealized gain (loss) on commodity contracts 2		$	(6,915	)		$	(7,410	)		$	13,807
	Realized gain on commodity contracts 2			6,185				12,349				933
	Unrealized gain (loss) on interest rate swap 3			258				(523	)			(47	)
	Realized loss on interest rate swap 3			(265	)			(111	)			(52	)
	Total activity for derivatives not designated as hedging instruments		$	(737	)		$	4,305			$	14,641
	2 Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(730), $4,939 and $14,740, for the years ended December 31, 2013, 2012 and 2011, respectively.
	3 Included in interest expense, net on the statements of operations.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Details Regarding Tax Effects of Temporary Differences That Gave Rise to the Deferred Tax Liabilities and Assets	'
	The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 were:
			As of December 31,
			2013				2012
	Deferred tax assets:
	Net operating loss carry-forward		$	20,892			$	17,196
	Asset retirement obligation			3,022				2,980
	Stock-based compensation			963				940
	Accrued compensation			25				28
	Net gas imbalance			134				139
	Other			64				63
				25,100				21,346
	Deferred tax liabilities:
	Derivative instruments			(65	)			(2,393	)
	Net basis difference in oil and gas properties			(26,271	)			(26,849	)
	Net deferred tax liability		$	(1,236	)		$	(7,896	)
Reconciliation of the Company's Effective Tax Rate to the Expected Federal Tax Rate	'
	The following table shows the reconciliation of the Company’s effective tax rate to the expected federal tax rate for the years ended December 31, 2013 and 2012:
		For the year ended December 31,
		2013				2012
	Expected federal tax rate		35	%			35	%
	Effect of permanent differences		-0.3	%			-0.78	%
	State tax rate		0.87	%			0.09	%
	Other		-1.82	%			0.1	%
	Effective tax rate		33.75	%			34.41	%

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Fair Values of Assets and Liabilities on a Recurring Basis	'
	The following tables provide a summary of assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012:
		Fair Value Measurements for the year ended December 31, 2013
		Level 1		Level 2		Level 3		Total
	Assets
	Derivative instruments -	$	-	$	607	$	-	$	607
	Commodity forward contracts
	Total assets as fair value	$	-	$	607	$	-	$	607
	Liabilities
	Derivative instruments -	$	-	$	97	$	-	$	97
	Commodity forward contracts
	Derivative instruments -		-		312		-		312
	Interest rate swap
	Total liabilities as fair value	$	-	$	409	$	-	$	409
		Fair Value Measurements for the year ended December 31, 2012
		Level 1		Level 2		Level 3		Total
	Assets
	Derivative instruments -	$	-	$	7,424	$	-	$	7,424
	Commodity forward contracts
	Total assets as fair value	$	-	$	7,424	$	-	$	7,424
	Liabilities
	Derivative instruments -	$	-	$	570	$	-	$	570
	Interest rate swap
	Total liabilities as fair value	$	-	$	570	$	-	$	570
Assets Measured at Fair Value on Nonrecurring Basis	'
	The following table provides a summary as of December 31, 2013 of assets measured at fair value on a nonrecurring basis:
		Level 1		Level 2		Level 3		Total
	Assets
	Oil and gas properties -	$	-	$	-	$	2,916	$	2,916
	Niobrara well
	Total assets as fair value	$	-	$	-	$	2,916	$	2,916

Compensation_Plans_Tables

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Assumptions Used in Estimating Fair Value of Share-based Awards	'
	The assumptions used in estimating the fair value of stock-options granted were:
		For the year ended December 31,
		2013 (1)		2012 (1)		2011
	Weighted-average volatility	n/a		n/a			61%
	Expected dividends	n/a		n/a			0.00%
	Expected term (in years)	n/a		n/a		4.75
	Risk-free rate	n/a		n/a			2.02%
	Expected forfeiture rate	n/a		n/a			8.00%
	-1	The Company did not grant any stock options in 2013 and 2012.
Summary of Stock Option Activity Under Stock Option Plans	'
	Summary of option activity during the year ended December 31, 2013:
			Shares				Weighted-		Weighted-		Aggregate
							Average		Average		Intrinsic
							Exercise		Remaining		Value
							Price		Contractual
									Term (in years)
	Options:
	Outstanding at January 1, 2013			419,350			$	11.06		2.9
	Granted		-
	Exercised		-
	Cancelled/expired			(142,496	)		$	10.81
	Outstanding at December 31, 2013			276,854			$	11.19		2.7	$	-
	Exercisable at December 31, 2013			250,143			$	11.81		2.7	$	-
Summary of Option Outstanding	'
	Stock options outstanding and currently exercisable at December 31, 2013 were as follows:
											Options Exercisable
	Range of Exercise		Number of				Options Outstanding		Weighted		Number of Options Exercisable		Weighted
	Prices per Share		Options				Weighted Average		Average				Average
			Outstanding				Remaining		Exercise Price				Exercise Price
							Contractual Life		per Share				per Share
							(in years)
	$4.33 - $5.10			68,503				3.3	$	4.74		47,191	$	4.7
	$6.78- $7.79			42,000				2.2	$	7.49		36,600	$	7.44
	$14.00 - $16.31			166,351				2.6	$	14.79		166,352	$	14.79
				276,854				2.7	$	11.19		250,143	$	11.81
Summary of Nonvested Stock Awards	'
	Nonvested stock awards as of December 31, 2013 and changes for the year ended December 31, 2013 were as follows:
			Shares				Weighted-
							Average
							Grant Date
							Fair Value
	Stock Awards:
	Outstanding at January 1, 2013			533,981			$	6.33
	Granted			90,715			$	4.01
	Vested			(215,198	)		$	5.72
	Forfeited/returned			(368,583	)		$	6.36
	Nonvested at December 31, 2013			40,915			$	4.12

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Annual Minimum Lease Payments	'
	The Company has entered into an operating lease through November 2015 for approximately 7,470 square feet of office space in Denver, Colorado. The Company also maintains operating leases various pieces of office equipment in both the Casper and Denver offices. The total annual minimum lease payments for the next five years and thereafter are:
	Year ending December 31,	Lease
		Commitments
	2014		139
	2015		132
	2016		-
	2017 and thereafter		-
	Total	$	271

Acquisition_of_Atlantic_Rim_Wo1

Acquisition of Atlantic Rim Working Interests (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Working Interest Acquired	'
	The following table summarizes the working interest acquired as a result of the transaction, and the Company’s post-transaction total ownership in each of the participating areas.
	Participating Area	Working Interest Acquired			Working Interest Following Purchase
	Catalina		14.33	%		85.53	%
	Sun Dog		8.73	%		28.59	%
	Doty Mountain		8.73	%		26.73	%
Amounts Recognized for Final Fair Value of Assets Acquired and Liabilities Assumed	'
	Amounts recognized for final fair value of assets acquired and liabilities assumed:
	Developed properties	$	6,877
	Asset retirement obligation	$	(2,003	)
	Total fair value of oil and gas properties acquired	$	4,874

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Capitalized Costs Relating to Oil and Gas Producing Activities and Aggregate Amount of Related Accumulated Depreciation	'
	The aggregate amount of capitalized costs relating to oil and natural gas producing activities and the aggregate amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011 were:
		As of December 31,
		2013			2012			2011
	Developed properties	$	238,332		$	225,382		$	209,774
	Wells in progress		2,342			10,963			8,182
	Undeveloped properties		2,705			2,734			2,921
			243,379			239,079			220,877
	Accumulated depletion and amortization		(127,372	)		(106,811	)		(88,639	)
	Net capitalized costs	$	116,007		$	132,268		$	132,238
Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities	'
	Costs incurred in property acquisitions, exploration, and development activities for the years ended December 31, 2013, 2012 and 2011 were:
		For the year ended December 31,
		2013			2012			2011
	Acquisitions
	Unproved properties	$	-		$	7		$	266
	Proved properties		-			4,874		-
	Exploration		-			7,279			16,311
	Development		9,622			11,166			9,203
	Total	$	9,622		$	23,326		$	25,780
Results of Operations from Oil and Gas Producing Activities	'
	The table below shows the results of operations for the Company’s oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011. All production is from within the continental United States.
		For the year ended December 31,
		2013			2012			2011
	Operating revenues (1)	$	37,969		$	38,923		$	45,093
	Costs and expenses:
	Production		17,041			15,299			15,412
	Exploration		181			696			273
	Depletion, amortization and impairment		25,372			24,159			18,439
	Total costs and expenses		42,594			40,154			34,124
	Income before income taxes		(4,625	)		(1,231	)		10,969
	Income tax expense (benefit)		(1,561	)		(422	)		3,863
	Results of operations	$	(3,064	)	$	(809	)	$	7,106
	-1	Operating revenues are comprised of the oil and gas sales from the consolidated statement of operations, plus settlements on the Company’s derivative instruments during the period included in price risk management activities on the consolidated statement of operations, totaling $6,185, $12,349 and $933, for the years ended December 31, 2013, 2012 and 2011, respectively.
Estimated Net Quantities of Proved Developed Reserves of Oil and Gas	'
	Estimated net quantities of proved developed reserves of oil and gas for the years ended December 31, 2013, 2012 and 2011 are:
		For the year ended December 31,
		2013						2012						2011
		Oil			Gas			Oil			Gas			Oil			Gas
		(Bbl)			(Mcf)			(Bbl)			(Mcf)			(Bbl)			(Mcf)
	Beginning of year		256,144			76,591,597			450,201			133,903,563			381,251			112,768,514
	Revisions of estimates		73,729			3,798,009			(164,126	)		(60,809,714	)		2,306			(834,305	)
	Extensions and discoveries		13,187			1,451,355			1,675			405,922			94,735			31,144,009
	Purchases of reserves	-			-			-			-			-			-
	Production		(29,082	)		(9,037,310	)		(31,606	)		(10,325,205	)		(28,091	)		(9,174,655	)
	End of year		313,978			72,803,651			256,144			76,591,597			450,201			133,903,563
	Proved developed reserves		207,999			58,588,355			207,881			71,146,164			245,124			80,121,740
	Percentage of proved developed reserves		66	%		80	%		81	%		93	%		54	%		60	%
Company's Standardized Measure	'
	Information with respect to the Company’s Standardized Measure is as follows:
		As of December 31,
		2013			2012			2011
	Future cash inflows	$	262,889		$	192,417		$	537,682
	Future production costs		(110,858	)		(92,868	)		(199,369	)
	Future development costs		(8,161	)		(6,502	)		(43,569	)
	Future income taxes		(13,532	)	-				(64,103	)
	Future net cash flows		130,338			93,047			230,641
	10% annual discount		(55,034	)		(34,822	)		(109,964	)
	Standardized Measure	$	75,304		$	58,225		$	120,677
Principal Changes in the Standardized Measure	'
	Principal changes in the Standardized Measure for the years ended December 31, 2013, 2012 and 2011 were as follows:
		2013			2012			2011
	Standard measure, as of January 1,	$	58,225		$	120,677		$	114,944
	Sales of oil and gas produced, net of production costs		(14,744	)		(24,586	)		(28,748	)
	Extensions and discoveries		1,776			343			28,130
	Net change in prices and production costs related to future production		31,546			(95,294	)		(1,363	)
	Development costs incurred during the year		381			4,231			6,014
	Changes in estimated future development costs		(2,646	)		23,945			(1,145	)
	Purchases of reserves in place		-			9,026		-
	Revisions of quantity estimates		2,936			(47,810	)		(932	)
	Accretion of discount		5,823			14,022			12,815
	Net change in income taxes		(2,879	)		33,512			(4,791	)
	Changes in timing and other  (1)		(5,114	)		20,159			(4,247	)
	Aggregate change		17,079			(62,452	)		5,733
	Standardized measure, as of December 31,	$	75,304		$	58,225		$	120,677
	-1	Due to the decrease in pricing for the year ended December 31, 2012, the economic life of the Company’s wells was shortened, causing the total discount taken on its future net cash flows to decrease.  The impact is included in the above table as Changes in timing and other.

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Quarterly Financial Data	'
	The following table contains a summary of the unaudited financial data for each quarter for the years ended December 31, 2013 and 2012 (in thousands except per share data):
		Fourth			Third			Second			First
		Quarter			Quarter			Quarter			Quarter
	Year ended December 31, 2013
	Oil and gas sales	$	8,150		$	7,599		$	8,502		$	7,533
	Income (loss) from operations	$	(9,235	)	$	(2,310	)	$	696		$	(7,577	)
	Net income (loss)	$	(6,406	)	$	(1,852	)	$	361		$	(5,176	)
	Net loss attributable to common stock	$	(7,337	)	$	(2,782	)	$	(570	)	$	(6,107	)
	Basic net loss per common share	$	(0.64	)	$	(0.25	)	$	(0.05	)	$	(0.54	)
	Diluted net loss per common share	$	(0.64	)	$	(0.25	)	$	(0.05	)	$	(0.54	)
	Year ended December 31, 2012
	Oil and gas sales	$	8,831		$	6,498		$	5,214		$	6,031
	Income (loss) from operations	$	(4,199	)	$	(5,207	)	$	(5,484	)	$	755
	Net income (loss)	$	(3,067	)	$	(3,568	)	$	(4,020	)	$	328
	Net loss attributable to common stock	$	(3,998	)	$	(4,498	)	$	(4,951	)	$	(603	)
	Basic net loss per common share	$	(0.36	)	$	(0.40	)	$	(0.44	)	$	(0.05	)
	Diluted net loss per common share	$	(0.36	)	$	(0.40	)	$	(0.44	)	$	(0.05	)

Business_Description_and_Summa3

Business Description and Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net changes in capitalized exploratory well costs	'	'	'
Beginning balance	'	$4,170	'
Additions to capitalized exploratory well costs pending the determination of proved reserves	'	6,650	16,198
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	'	-6,390	-12,028
Capitalized exploratory well costs charged to expense	'	-4,430	'
Ending balance	'	'	$4,170

Business_Description_and_Summa4

Business Description and Summary of Significant Accounting Policies (Details 1) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	($6,406)	($1,852)	$361	($5,176)	($3,067)	($3,568)	($4,020)	$328	($13,073)	($10,327)	$11,687
Preferred stock dividends	'	'	'	'	'	'	'	'	-3,723	-3,723	-3,723
Income (loss) attributable to common stock	($7,337)	($2,782)	($570)	($6,107)	($3,998)	($4,498)	($4,951)	($603)	($16,796)	($14,050)	$7,964
Weighted average shares:	'	'	'	'	'	'	'	'	'	'	'
Weighted average shares - basic	'	'	'	'	'	'	'	'	11,332,129	11,250,513	11,191,496
Dilutive effect of stock options outstanding at the end of period	'	'	'	'	'	'	'	'	'	'	19,108
Weighted average shares - fully diluted	'	'	'	'	'	'	'	'	11,332,129	11,250,513	11,210,604
Net income (loss) per share:	'	'	'	'	'	'	'	'	'	'	'
Basic	($0.64)	($0.25)	($0.05)	($0.54)	($0.36)	($0.40)	($0.44)	($0.05)	($1.48)	($1.25)	$0.71
Diluted	($0.64)	($0.25)	($0.05)	($0.54)	($0.36)	($0.40)	($0.44)	($0.05)	($1.48)	($1.25)	$0.71

Business_Description_and_Summa5

Business Description and Summary of Significant Accounting Policies (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effect of anti-dilutive shares	'	'	'
Potential common shares	28,612	58,704	48,724

Business_Description_and_Summa6

Business Description and Summary of Significant Accounting Policies (Details Textual) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Cash and Cash Equivalents Maturity Period	'90 days	'	'
Unexpended portion of Escrow deposits	$283	$565	'
Natural gas imbalance receivable	327	'	'
Natural gas imbalance payable	900	'	'
Depreciation, depletion and amortization	20,942	20,216	18,844
Accretion expense	276	188	174
Impairment and abandonment of equipment and properties	4,992	4,988	187
Gas transportation pipeline	5,510	5,510	'
Depreciation on Company's pipeline facilities	130,518	109,606	'
Percentage of natural gas in total production	98.00%	'	'
Percentage of natural gas in total reserve	97.00%	'	'
Impairment of Oil and Gas Properties	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Depreciation, depletion and amortization	20,560	19,828	18,439
Impairment and abandonment of equipment and properties	4,962	4,901	0
Impairment of leasehold	30	87	187
Impairment Of Well	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Impairment and abandonment of equipment and properties	'	4,430	'
Additional Impairment Expense	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Impairment and abandonment of equipment and properties	4,812	'	'
Pipelines	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Gas transportation pipeline	5,510	'	'
Estimated useful life	'25 years	'	'
Depreciation on Company's pipeline facilities	$221	'	'
Gas Imbalance Receivable	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Volume of natural gas imbalance	115,000	'	'
Gas Imbalance Payable	'	'	'
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Volume of natural gas imbalance	241,000	'	'

Business_Description_and_Summa7

Business Description and Summary of Significant Accounting Policies (Details Textual 1) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Customer	Customer	Customer
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Depreciation, depletion and amortization	$20,942	$20,216	$18,844
Sales to Major Customers	35,319	38,165	64,703
Business Description and Summary of Significant Accounting Policies (Textual) [Abstract]	'	'	'
Sales Percentage	10.00%	10.00%	10.00%
Number of Customers	1	1	1
Employer contributions	197	226	221
Dividends declared and paid on preferred stock	3,723	3,723	3,723
Dividends declared and paid on preferred stock, per share	$0.58	$0.58	$0.58
Allowance for uncollectible receivables	0	0	0
Unaffiliated Customer	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Sales to Major Customers	26,360	23,145	22,159
Depreciation Expenses	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Depreciation, depletion and amortization	$161	$167	$186
Vehicles	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'7 years	'	'
Minimum | Office Facilities	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'10 years	'	'
Minimum | Office Equipment	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'3 years	'	'
Maximum | Office Facilities	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'40 years	'	'
Maximum | Office Equipment	'	'	'
Description Of Business And Summary Of Significant Accounting Policies [Line Items]	'	'	'
Estimated useful life	'10 years	'	'

Credit_Facility_Details

Credit Facility (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 09, 2014
				Minimum	Maximum	Interest expense, net	Interest expense, net	Interest expense, net	Subsequent Event
Credit Facility (Additional Textual) [Abstract]	'	'	'	'	'	'	'	'	'
Company revolving line of credit	$150,000	'	'	'	'	'	'	'	'
Amount available for borrowing	60,000	'	'	'	'	'	'	'	55,000
Date of balance outstanding on the credit facility	24-Oct-16	'	'	'	'	'	'	'	'
Credit facility	47,450	47,450	'	'	'	'	'	'	'
Federal Funds rate	0.50%	'	'	'	'	'	'	'	'
Average interest rate on the facility	3.30%	'	'	'	'	'	'	'	'
Interest capitalized	80	321	155	'	'	'	'	'	'
Credit Facility (Textual) [Abstract]	'	'	'	'	'	'	'	'	'
Interest expense, net	$1,307	$1,610	$1,317	'	'	$1,635	$1,275	$1,070	'
Margin on the level of funds borrowed, rate	'	'	'	0.75%	2.75%	'	'	'	'
Current ratio of the company	1	'	'	'	'	'	'	'	'
Ratio of EBITDAX	1.5	'	'	'	'	'	'	'	'
Funded debt to EBITDAX ratio	3.5	'	'	'	'	'	'	'	'

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of asset retirement obligation liability	'	'	'
Beginning asset retirement obligation	$8,494	$6,300	'
Liabilities incurred	368	12	'
Liabilities settled	-258	-9	'
Accretion expense	276	188	174
Additional liabilities assumed through acquisition	'	2,003	'
Revision to estimated cash flows	-460	'	'
Ending asset retirement obligation	$8,420	$8,494	$6,300

Derivative_Instruments_Details

Derivative Instruments (Details)	Dec. 31, 2013
	Mcf
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	14,395,000
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	1,825,000
Contract Price	4.27
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-14
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-14
Costless Collar Floor	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	1,800,000
Contract Price	4
Price Index	'NYMEX
Costless Collar Floor | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-14
Costless Collar Floor | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-14
Costless Collar Ceiling	'
Commodity volumes under derivative contracts	'
Contract Price	4.5
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	1,800,000
Contract Price	4.2
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-14
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-14
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	540,000
Contract Price	4.17
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-14
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-14
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	3,000,000
Contract Price	4.28
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-15
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-15
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	3,600,000
Contract Price	4.15
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-15
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-15
Fixed Price Swap	'
Commodity volumes under derivative contracts	'
Remaining Contractual Volume	1,830,000
Contract Price	4.07
Price Index	'NYMEX
Fixed Price Swap | Minimum	'
Commodity volumes under derivative contracts	'
Term	'--01-16
Fixed Price Swap | Maximum	'
Commodity volumes under derivative contracts	'
Term	'--12-16

Derivative_Instruments_Details1

Derivative Instruments (Details 1) (Interest Rate Swap One, USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Summary of interest rate swaps with a third party	'
Contractual Amount	$30,000
Rate (LIBOR)	1.05%
Effective Interest Rate	3.55%	[1]
Minimum	'
Summary of interest rate swaps with a third party	'
Term	31-Dec-12
Maximum	'
Summary of interest rate swaps with a third party	'
Term	30-Sep-16
[1]	Not applicable as the Company did not have any cash flow hedges in the years ended December 31, 2013 and 2012

Derivative_Instruments_Details2

Derivative Instruments (Details 2) (Not Designated as Hedging Instrument, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Liabilities	'	'
Total	($422)	($570)
Commodity Derivatives	'	'
ASSETS	'	'
Fair value, asset	620	7,424
Commodity Derivatives | Assets from price risk management - current	'	'
ASSETS	'	'
Fair value, asset	218	6,742
Commodity Derivatives | Assets from price risk management - long term	'	'
ASSETS	'	'
Fair value, asset	402	682
Commodity Derivatives | Liabilities from price risk management - current	'	'
Liabilities	'	'
Fair value, liability	-13	'
Commodity Derivatives | Liabilities from price risk management -long term	'	'
Liabilities	'	'
Fair value, liability	-97	'
Interest Rate Swap | Other current liabilities	'	'
Liabilities	'	'
Fair value, liability	-222	-200
Interest Rate Swap | Other long term liabilities	'	'
Liabilities	'	'
Fair value, liability	($90)	($370)

Derivative_Instruments_Details3

Derivative Instruments (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	'		'		'
Location of Gain Recognized in Income (Ineffective) Portion and Amount Excluded from Effectiveness Testing	'	[1]	'	[1]	'
Commodity contracts	'		'		'
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	'		'		'
Amount of Gain Recognized in OCI on Derivative	'		'		997
Oil and gas sales	'		'		'
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	'		'		'
Amount of Gain Reclassified from AOCI into Income	'		'		$9,592
[1]	Not applicable as the Company did not have any cash flow hedges in the years ended December 31, 2013 and 2012

Derivative_Instruments_Details4

Derivative Instruments (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations	'		'		'
Unrealized gain (loss) on commodity contracts	($6,915)	[1]	($7,410)	[1]	$13,807	[1]
Realized gain on commodity contracts	6,185	[1]	12,349	[1]	933	[1]
Unrealized loss on interest rate swap	258	[2]	-523	[2]	-47	[2]
Realized loss on interest rate swap	-265	[2]	-111	[2]	-52	[2]
Total activity for derivatives not designated as hedging instruments	($737)		$4,305		$14,641
[1]	Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(730), $4,939 and $14,740, for the years ended DecemberB 31, 2013, 2012 and 2011, respectively.
[2]	Included in interest expense, net on the statements of operations.

Derivative_Instruments_Details5

Derivative Instruments (Details 4) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations	'	'	'
Price risk management activities	($730)	$4,939	$14,740

Derivative_Instruments_Details6

Derivative Instruments (Details Textual) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Derivative Instruments (Additional Textual) [Abstract]	'
Hedging up projected proved for twelve months, rate	90.00%
Hedging up projected proved for twenty four month, rate	80.00%
Interest Rate Swap	'
Derivative Instruments (Additional Textual) [Abstract]	'
Derivative instruments	30

Income_Taxes_Details

Income Taxes (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets:	'	'
Net operating loss carry-forward	$20,892	$17,196
Asset retirement obligation	3,022	2,980
Stock-based compensation	963	940
Accrued compensation	25	28
Net gas imbalance	134	139
Other	64	63
Total	25,100	21,346
Deferred tax liabilities:	'	'
Derivative instruments	-65	-2,393
Net basis difference in oil and gas properties	-26,271	-26,849
Net deferred tax liability	($1,236)	($7,896)

Income_Taxes_Details_1

Income Taxes (Details 1)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of the Company's effective tax rate to the expected federal tax rate	'	'
Expected federal tax rate	35.00%	35.00%
Effect of permanent differences	-0.30%	-0.78%
State tax rate	0.87%	0.09%
Other	-1.82%	0.10%
Effective tax rate	33.75%	34.41%

Income_Taxes_Details_Textual

Income Taxes (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2013
Income Taxes (Textual) [Abstract]	'
Net operating loss carry forward for regular income tax	$59,000,000
Year of expiring of operating loss carry forward	'2021
Provision for interest or penalties related to uncertain tax position	$0
Income tax examination, federal or state income taxes	'The Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2010 and for state and local tax authorities for years before 2009.

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (Fair Value, Measurements, Recurring, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Total assets as fair value	$607	$7,424
Total liabilities as fair value	409	570
Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Total assets as fair value	'	'
Total liabilities as fair value	'	'
Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Total assets as fair value	607	7,424
Total liabilities as fair value	409	570
Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Total assets as fair value	'	'
Total liabilities as fair value	'	'
Commodity Forward Contracts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	607	7,424
Derivative instruments	97	'
Commodity Forward Contracts | Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	'	'
Derivative instruments	'	'
Commodity Forward Contracts | Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	607	7,424
Derivative instruments	97	'
Commodity Forward Contracts | Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	'	'
Derivative instruments	'	'
Interest Rate Swap	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	312	570
Interest Rate Swap | Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	'	'
Interest Rate Swap | Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	312	570
Interest Rate Swap | Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative instruments	'	'

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 1) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Developed properties	$238,332	$225,382	$209,774
Fair Value, Measurements, Nonrecurring	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Total assets as fair value	2,916	'	'
Fair Value, Measurements, Nonrecurring | Niobrara well	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Developed properties	2,916	'	'
Fair Value, Measurements, Nonrecurring | Level 1	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Total assets as fair value	'	'	'
Fair Value, Measurements, Nonrecurring | Level 1 | Niobrara well	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Developed properties	'	'	'
Fair Value, Measurements, Nonrecurring | Level 2	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Total assets as fair value	'	'	'
Fair Value, Measurements, Nonrecurring | Level 2 | Niobrara well	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Developed properties	'	'	'
Fair Value, Measurements, Nonrecurring | Level 3	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Total assets as fair value	2,916	'	'
Fair Value, Measurements, Nonrecurring | Level 3 | Niobrara well	'	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'	'
Developed properties	$2,916	'	'

Preferred_Stock_and_Stockholde1

Preferred Stock and Stockholder's Equity (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
			Series A Cumulative Preferred Stock	Series A Preferred Stock
Preferred Stock and Stockholders Equity (Textual) [Abstract]	'	'	'	'
Price of Series A Preferred Stock	'	'	$25	$25
Preferred stock, shares authorized	10,000,000	10,000,000	10,000,000	'
Preferred stock, shares issued	1,610,000	1,610,000	1,610,000	'
Percentage of Series A Cumulative Preferred Stock	'	'	9.25%	'
Preferred Stock, dividend rate	'	'	'	$2.31
Preferred Stock, redemption terms	'	'	'	'Following a change of ownership or control of the Company by a person or entity in which the common stock of the Company is no longer traded on a national exchange, the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control occurred for cash.

Compensation_Plans_Details

Compensation Plans (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Assumptions used in estimating fair value of share-based awards	'		'		'
Weighted-average volatility, Maximum	'	[1]	'	[1]	61.00%
Expected dividends	'	[1]	'	[1]	0.00%
Expected term (in years)	'		'		'4 years 9 months
Risk-free rate, Maximum	'	[1]	'	[1]	2.02%
Expected forfeiture rate	'	[1]	'	[1]	8.00%
[1]	The Company did not grant any stock options in 2013 and 2012.

Compensation_Plans_Details_1

Compensation Plans (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary of stock option activity under the Company's various stock option plans	'	'
Outstanding Shares, Beginning	419,350	'
Shares, Granted	'	'
Stock options exercised, cashless, shares	'	'
Shares, Cancelled/expired	-142,496	'
Outstanding Shares, Closing	276,854	419,350
Shares, Exercisable	250,143	'
Weighted-Average Exercise Price, Outstanding, Beginning	$11.06	'
Weighted-Average Exercise Price, Cancelled/expired	$10.81	'
Weighted-Average Exercise Price, Outstanding, Ending	$11.19	$11.06
Weighted-Average Exercise Price, Exercisable	$11.81	'
Weighted-Average Remaining Contractual Term (in years), Outstanding	'2 years 8 months 12 days	'2 years 10 months 24 days
Weighted-Average Remaining Contractual Term (in years), Exercisable	'2 years 8 months 12 days	'
Aggregated Intrinsic Value, Outstanding	'	'
Aggregate Intrinsic Value, Exercisable	'	'

Compensation_Plans_Details_2

Compensation Plans (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Number of Options Outstanding	276,854
Options Outstanding, Weighted Average Remaining Contractual Life (in years)	'2 years 8 months 12 days
Weighted Average Exercise Price per Share	$11.19
Options Exercisable, Number of Options Exercisable	250,143
Options Exercisable, Weighted Average Exercise Price per Share	$11.81
Range One	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Share-based compensation, shares authorized under stock option plans, exercise price range, lower range limit	$4.33
Share-based compensation, shares authorized under stock option plans, exercise price range, upper range limit	$5.10
Number of Options Outstanding	68,503
Options Outstanding, Weighted Average Remaining Contractual Life (in years)	'3 years 3 months 18 days
Weighted Average Exercise Price per Share	$4.74
Options Exercisable, Number of Options Exercisable	47,191
Options Exercisable, Weighted Average Exercise Price per Share	$4.70
Range Two	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Share-based compensation, shares authorized under stock option plans, exercise price range, lower range limit	$6.78
Share-based compensation, shares authorized under stock option plans, exercise price range, upper range limit	$7.79
Number of Options Outstanding	42,000
Options Outstanding, Weighted Average Remaining Contractual Life (in years)	'2 years 2 months 12 days
Weighted Average Exercise Price per Share	$7.49
Options Exercisable, Number of Options Exercisable	36,600
Options Exercisable, Weighted Average Exercise Price per Share	$7.44
Range Three	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Share-based compensation, shares authorized under stock option plans, exercise price range, lower range limit	$14
Share-based compensation, shares authorized under stock option plans, exercise price range, upper range limit	$16.31
Number of Options Outstanding	166,351
Options Outstanding, Weighted Average Remaining Contractual Life (in years)	'2 years 7 months 6 days
Weighted Average Exercise Price per Share	$14.79
Options Exercisable, Number of Options Exercisable	166,352
Options Exercisable, Weighted Average Exercise Price per Share	$14.79

Compensation_Plans_Details_3

Compensation Plans (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2013
Summary of nonvested stock awards	'
Shares Nonvested, Beginning Balance	533,981
Shares, Granted	90,715
Shares, Vested	-215,198
Shares, Forfeited/returned	-368,583
Shares Nonvested, Ending Balance	40,915
Weighted-Average Grant Date Fair Value, Nonvested, Beginning Balance	$6.33
Weighted-Average Grant Date Fair Value, Granted	$4.01
Weighted-Average Grant Date Fair Value, Vested	$5.72
Weighted-Average Grant Date Fair Value, Forfeited/returned	$6.36
Weighted-Average Grant Date Fair Value, Nonvested, Ending Balance	$4.12

Compensation_Plans_Details_Tex

Compensation Plans (Details Textual) (USD $)

12 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 01, 2014

Minimum

Maximum

Two Thousand Two Stock Option Plan

Two Thousand Three Stock Option Plan

Two Thousand Seven Stock Option Plan

Two Thousand Ten Stock Option Plan

Employee Stock Option

Long Term Incentive Plan

Long Term Incentive Plan

Long Term Incentive Plan

Long Term Incentive Plan

Subsequent Event

Compensation Plans (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual vested period

'

'

'

'2 years

'5 years

'

'

'

'

'

'

'

'

'

Expiration of option granted

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

Recognized Weighted Average period of stock compensation

'8 months 12 days

'

'

'

'

'

'

'

'

'1 year 2 months 12 days

'

'

'

'

Stock-based compensation expense

$744,000

$1,341,000

$1,153,000

'

'

'

'

'

'

'

$317

$462

$161

'

Aggregate share of common stock

'

'

'

'

'

24,971

39,998

424,409

388,508

'

'

'

'

'

Shares granted to certain executive management

'

'

'

'

'

'

'

'

'

'

'

'

'

181,903

Shares vested due to continuous employment

'

'

'

'

'

'

'

'

'

'

135,421

'

'

'

Compensation Plans (Additional Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average grant date fair value

'

'

$2.65

'

'

'

'

'

'

'

'

'

'

'

Total intrinsic value of option exercised

'

'

9

'

'

'

'

'

'

'

'

'

'

'

Intrinsic value of option vested and exercisable

0

0

89

'

'

'

'

'

'

'

'

'

'

'

Un-recognized stock based compensation expense related to Stock option

21

'

'

'

'

'

'

'

'

'

'

'

'

'

Un-recognized stock based compensation expense related to non vested stock option stock option

132

'

'

'

'

'

'

'

'

'

'

'

'

'

Intrinsic value of restricted stock awards vested

$642

$372

$457

'

'

'

'

'

'

'

'

'

'

'

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Annual Minimum Lease Payments	'
2014	$139
2015	132
2016	'
2017 and thereafter	'
Total	$271

Commitments_and_Contingencies_2

Commitments and Contingencies (Details Textual) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	sqft
Commitments and Commitments (Textual) [Abstract]	'	'	'
Lease period	'November 2015	'	'
Contractual area under operating lease commitment	7,470	'	'
Operating lease expenses, total	$2,634	$2,888	$2,049

Acquisition_of_Atlantic_Rim_Wo2

Acquisition of Atlantic Rim Working Interests (Details)	Dec. 31, 2013
Catalina Unit	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'
Working Interest Acquired	14.33%
Working Interest Following Purchase	85.53%
Sun Dog	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'
Working Interest Acquired	8.73%
Working Interest Following Purchase	28.59%
Doty Mountain	'
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]	'
Working Interest Acquired	8.73%
Working Interest Following Purchase	26.73%

Acquisition_of_Atlantic_Rim_Wo3

Acquisition of Atlantic Rim Working Interests (Details 1) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Amounts recognized for final fair value of assets acquired and liabilities assumed	'
Developed properties	$6,877
Asset retirement obligation	-2,003
Total fair value of oil and gas properties acquired	$4,874

Acquisition_of_Atlantic_Rim_Wo4

Acquisition of Atlantic Rim Working Interest (Details Textual) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013
Acquisition of Atlantic Rim Working Interest (Textual) [Abstract]	'	'
Working Interest Acquired	100.00%	'
Effective date of transaction of purchase price allocation base on estimated fair value	1-Aug-12	'
Purchase price allocated to assets acquired and liabilities assumed	'	$4,874

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Gas Producing Activities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized costs relating to oil and gas producing activities and aggregate amount of related accumulated depreciation	'	'	'
Developed properties	$238,332	$225,382	$209,774
Wells in progress	2,342	10,963	8,182
Undeveloped properties	2,705	2,734	2,921
Total	243,379	239,079	220,877
Accumulated depletion and amortization	-127,372	-106,811	-88,639
Net capitalized costs	$116,007	$132,268	$132,238

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Gas Producing Activities (Details 1) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs incurred in oil and gas property acquisitions, exploration and development activities	'	'	'
Unproved properties	'	$7	$266
Proved properties	'	4,874	'
Exploration	'	7,279	16,311
Development	9,622	11,166	9,203
Total	$9,622	$23,326	$25,780

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Gas Producing Activities (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations from oil and gas producing activities	'	'	'
Operating revenues	$37,969	$38,923	$45,093
Costs and expenses:	'	'	'
Production	17,041	15,299	15,412
Exploration	181	696	273
Depletion, amortization and impairment	25,372	24,159	18,439
Total costs and expenses	42,594	40,154	34,124
Income before income taxes	-4,625	-1,231	10,969
Income tax expense (benefit)	-1,561	-422	3,863
Results of operations	($3,064)	($809)	$7,106

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Gas Producing Activities (Details 2) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Results of Operations from oil and gas producing activities	'		'		'
Settlements on derivatives	$6,185	[1]	$12,349	[1]	$933	[1]
[1]	Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(730), $4,939 and $14,740, for the years ended DecemberB 31, 2013, 2012 and 2011, respectively.

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Gas Producing Activities (Details 3)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	bbl	bbl	bbl
Estimated net quantities of proved developed reserves of oil and gas	'	'	'
End of year	74,700	'	'
Oil	'	'	'
Estimated net quantities of proved developed reserves of oil and gas	'	'	'
Beginning of year	256,144	450,201	381,251
Revisions of estimates	73,729	-164,126	2,306
Extensions and discoveries	13,187	1,675	94,735
Purchases of reserves	'	'	'
Production	-29,082	-31,606	-28,091
End of year	313,978	256,144	450,201
Proved developed reserves	207,999	207,881	245,124
Percentage of proved developed reserves	66.00%	81.00%	54.00%
Natural Gas	'	'	'
Estimated net quantities of proved developed reserves of oil and gas	'	'	'
Beginning of year	76,591,597	133,903,563	112,768,514
Revisions of estimates	3,798,009	-60,809,714	-834,305
Extensions and discoveries	1,451,355	405,922	31,144,009
Purchases of reserves	'	'	'
Production	-9,037,310	-10,325,205	-9,174,655
End of year	72,803,651	76,591,597	133,903,563
Proved developed reserves	58,588,355	71,146,164	80,121,740
Percentage of proved developed reserves	80.00%	93.00%	60.00%

Supplemental_Information_on_Oi7

Supplemental Information on Oil and Gas Producing Activities (Details 4) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Company's Standardized Measure	'	'	'
Future cash inflows	$262,889	$192,417	$537,682
Future production costs	-110,858	-92,868	-199,369
Future development costs	-8,161	-6,502	-43,569
Future income taxes	-13,532	'	-64,103
Future net cash flows	130,338	93,047	230,641
10% annual discount	-55,034	-34,822	-109,964
Standardized Measure	$75,304	$58,225	$120,677

Supplemental_Information_on_Oi8

Supplemental Information on Oil and Gas Producing Activities (Details 5) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Principal changes in the Standardized Measure	'	'	'
Standard measure, Beginning Balance	$58,225	$120,677	$114,944
Sales of oil and gas produced, net of production costs	-14,744	-24,586	-28,748
Extensions and discoveries	1,776	343	28,130
Net change in prices and production costs related to future production	31,546	-95,294	-1,363
Development costs incurred during the year	381	4,231	6,014
Changes in estimated future development costs	-2,646	23,945	-1,145
Purchases of reserves in place	'	9,026	'
Revisions of quantity estimates	2,936	-47,810	-932
Accretion of discount	5,823	14,022	12,815
Net change in income taxes	-2,879	33,512	-4,791
Changes in timing and other	-5,114	20,159	-4,247
Aggregate change	17,079	-62,452	5,733
Standardized measure, Ending Balance	$75,304	$58,225	$120,677

Supplemental_Information_on_Oi9

Supplemental Information on Oil and Gas Producing Activities (Details Textual)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Mcf	Oil	Oil	Oil	Oil	Natural Gas	Natural Gas	Natural Gas	Natural Gas
		bbl	bbl	bbl	bbl	Mcf	Mcf	Mcf	Mcf
Supplemental Information on Oil and Gas Producing Activities (Textual) [Abstract]	'	'	'	'	'	'	'	'	'
Estimated proved reserves	74,700	313,978	256,144	450,201	381,251	72,803,651	76,591,597	133,903,563	112,768,514
Percentage of proved developed reserves	'	66.00%	81.00%	54.00%	'	80.00%	93.00%	60.00%	'
Discount rate on proved gas And oil reserves	10.00%	'	'	'	'	'	'	'	'
Average pricing period of oil and gas	'12 months	'	'	'	'	'	'	'	'

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of Quarterly Financial Data	'	'	'	'	'	'	'	'	'	'	'
Oil and gas sales	$8,150	$7,599	$8,502	$7,533	$8,831	$6,498	$5,214	$6,031	$31,784	$26,574	$44,160
Income (loss) from operations	-9,235	-2,310	696	-7,577	-4,199	-5,207	-5,484	755	'	'	'
Net income (loss)	-6,406	-1,852	361	-5,176	-3,067	-3,568	-4,020	328	-13,073	-10,327	11,687
Income (loss) attributable to common stock	($7,337)	($2,782)	($570)	($6,107)	($3,998)	($4,498)	($4,951)	($603)	($16,796)	($14,050)	$7,964
Basic net loss per common share	($0.64)	($0.25)	($0.05)	($0.54)	($0.36)	($0.40)	($0.44)	($0.05)	($1.48)	($1.25)	$0.71
Diluted net loss per common share	($0.64)	($0.25)	($0.05)	($0.54)	($0.36)	($0.40)	($0.44)	($0.05)	($1.48)	($1.25)	$0.71