Callon Petroleum (CPE) 10-K 13 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Mar. 10, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'CALLON PETROLEUM CO	'	'
Entity Central Index Key	'0000928022	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	40,465,227	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$129.60

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$3,012	$1,139
Accounts receivable	20,586	15,608
Fair market value of derivatives	60	1,674
Deferred tax asset, current	3,843	0
Other current assets	2,063	1,502
Total current assets	29,564	19,923
Oil and natural gas properties, full-cost accounting method:	'	'
Evaluated properties	1,701,577	1,497,010
Less accumulated depreciation, depletion and amortization	-1,420,612	-1,296,265
Net oil and natural gas properties	280,965	200,745
Unevaluated properties excluded from amortization	43,222	68,776
Total oil and natural gas properties	324,187	269,521
Other property and equipment, net	7,255	10,058
Restricted investments	3,806	3,798
Investment in Medusa Spar LLC	0	8,568
Deferred tax asset	57,765	64,383
Other assets, net	1,376	1,922
Total assets	423,953	378,173
Current liabilities:	'	'
Accounts payable and accrued liabilities	57,637	36,016
Asset retirement obligations	4,120	2,336
Fair market value of derivatives	1,036	125
Total current liabilities	62,793	38,477
13% Senior Notes:	'	'
Principal outstanding	48,481	96,961
Deferred credit, net of accumulated amortization of $20,814 and $17,800, respectively	5,267	13,707
Total 13% Senior Notes	53,748	110,668
Credit facility	22,000	10,000
Asset retirement obligations	2,612	10,965
Other long-term liabilities	3,706	2,092
Total liabilities	144,859	172,202
Stockholders' equity:	'	'
Preferred Stock, series A cumulative, $.01 par value and $50.00 liquidation preference, 2,500 shares authorized; 1,579 and 0 shares outstanding, respectively	16	0
Common Stock, $.01 par value, 60,000 shares authorized; 40,345 and 39,801 shares outstanding at December 31, 2013 and 2012, respectively	404	398
Capital in excess of par value	401,540	328,116
Retained deficit	-122,866	-122,543
Total stockholders' equity	279,094	205,971
Total liabilities and stockholders' equity	$423,953	$378,173

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
LIABILITIES AND STOCKHOLDERS' EQUITY	'	'
Accumulated amortization of deferred credit	$20,814	$17,800
Stockholders' equity:	'	'
Preferred stock, par value (in dollars per share)	$0.01	$0.01
Preferred stock, liquidation preference (in dollars per share)	$50	$50
Preferred stock, shares authorized	2,500,000	2,500,000
Preferred stock, shares outstanding	1,579,000	0
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, shares authorized	60,000,000	60,000,000
Common stock, shares outstanding	40,345,000	39,801,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating revenues:	'		'		'
Oil sales	$88,960		$96,584		$100,962
Natural gas sales	13,609		14,149		26,682
Total operating revenues	102,569		110,733		127,644
Operating expenses:	'		'		'
Lease operating expenses	19,779		23,330		18,285
Production taxes	4,133		3,224		2,062
Depreciation, depletion and amortization	43,967		49,701		48,701
General and administrative	20,534		20,358		16,636
Accretion expense	1,785		2,253		2,338
Impairment of other property and equipment	1,707		1,177		0
Total operating expenses	91,905		100,043		88,022
Income from operations	10,664		10,690		39,622
Other (income) expenses:	'		'		'
Interest expense	6,094		9,108		11,717
Gain on early extinguishment of debt	-3,696		-1,366		-1,942
Gain on acquired equipment	0		0		-5,041
Loss (gain) on derivative contracts	1,360		-1,717		0
Other income	-485		-79		-1,426
Total other expenses	3,273		5,946		3,308
Income before income taxes	7,391		4,744		36,314
Income tax expense (benefit)	3,104		2,223		-69,283
Income before equity in earnings of Medusa Spar LLC	4,287		2,521		105,597
Equity in earnings of Medusa Spar LLC, net of tax	17		226		799
Net income	4,304		2,747		106,396
Preferred stock dividends	-4,627		0		0
Income (loss) available to common shareholders	($323)		$2,747		$106,396
Income (loss) per common share:	'		'		'
Basic (in dollars per share)	($0.01)		$0.07		$2.81
Diluted (in dollars per share)	($0.01)		$0.07		$2.76
Shares used in computing income per common share:	'		'		'
Basic (in shares)	40,133		39,522		37,908
Diluted (in shares)	40,133	[1]	40,337	[1]	38,582	[1]
[1]	Because the Company reported a loss for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive.

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
Statement of Comprehensive Income [Abstract]	'	'	'
Net income	$4,304	$2,747	$106,396
Other comprehensive income (loss):	'	'	'
Change in fair value of derivatives designated as hedges, net of tax	0	-1,624	2,561
Comprehensive income	4,304	1,123	108,957
Preferred stock dividends	-4,627	0	0
Comprehensive income (loss) available to common shareholders	($323)	$1,123	$108,957

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Accumulated Other Comprehensive Income (Loss)	Retained Earnings (Deficit)
In Thousands, unless otherwise specified
Balance at Dec. 31, 2010	$15,810	$0	$290	$248,160	($937)	($231,703)
Comprehensive income:	'	'	'	'	'	'
Net income	106,396	'	'	'	'	106,396
Other comprehensive income	'	'	'	'	2,561	'
Total comprehensive income	108,957	'	'	'	'	'
Shares issued pursuant to employee benefit plans	207	'	'	207	'	'
Restricted stock	2,449	'	3	2,446	'	'
Stock issued	73,762	'	101	73,661	'	'
Reconsolidated subsidiary (See Note 13)	17	'	'	'	'	17
Balance at Dec. 31, 2011	201,202	0	394	324,474	1,624	-125,290
Comprehensive income:	'	'	'	'	'	'
Net income	2,747	'	'	'	'	2,747
Other comprehensive income	'	'	'	'	-1,624	'
Total comprehensive income	1,123	'	'	'	'	'
Shares issued pursuant to employee benefit plans	235	'	'	235	'	'
Restricted stock	3,411	'	4	3,407	'	'
Balance at Dec. 31, 2012	205,971	0	398	328,116	0	-122,543
Comprehensive income:	'	'	'	'	'	'
Net income	4,304	'	'	'	'	'
Total comprehensive income	4,304	'	'	'	0	4,304
Shares issued pursuant to employee benefit plans	243	'	'	243	'	'
Restricted stock	3,168	'	6	3,162	'	'
Stock issued	70,035	16	'	70,019	'	'
Preferred stock dividend	-4,627	'	'	'	'	-4,627
Balance at Dec. 31, 2013	$279,094	$16	$404	$401,540	$0	($122,866)

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	$4,304	$2,747	$106,396
Adjustments to reconcile net income to cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	45,393	51,043	49,753
Accretion expense	1,785	2,253	2,338
Amortization of non-cash debt related items	471	402	461
Amortization of deferred credit	-3,164	-3,086	-3,155
Equity in earnings of Medusa Spar LLC	-17	-226	-799
Deferred income tax expense	2,778	2,223	10,928
Valuation allowance	0	0	-80,211
Net loss (gain) on derivatives, net of settlements	2,730	-1,683	0
Impairment of other property and equipment	1,707	1,176	0
Gain on acquired equipment	0	0	-4,995
Non-cash gain for early debt extinguishment	-3,696	-1,366	-1,942
Non-cash expense related to equity share-based awards	2,092	1,697	1,337
Change in the fair value of liability share-based awards	2,903	1,620	761
Payments to settle asset retirement obligations	-721	-1,314	-2,563
Changes in current assets and liabilities:	'	'	'
Accounts receivable	-3,497	-883	-3,734
Other current assets	-560	100	180
Current liabilities	3,583	1,753	4,695
Payments to settle vested liability share-based awards	-239	-3,383	0
Change in natural gas balancing receivable	22	51	252
Change in natural gas balancing payable	-527	-102	-115
Change in other long-term liabilities	-206	205	100
Change in other assets, net	-812	-1,937	-520
Net cash provided by operating activities	54,329	51,290	79,167
Cash flows from investing activities:	'	'	'
Capital expenditures	-159,724	-133,299	-100,243
Acquisitions	-10,885	-2,075	0
Proceeds from sale of mineral interests and equipment	89,992	39,936	7,615
Investment in restricted assets related to plugging and abandonment	0	0	-150
Distribution from Medusa Spar LLC	813	1,735	1,267
Net cash used in investing activities	-79,804	-93,703	-91,511
Cash flows from financing activities:	'	'	'
Borrowings on credit facility	80,000	53,000	0
Payments on credit facility	-68,000	-43,000	0
Redemption of 13% Senior Notes	-50,060	-10,225	-35,062
Issuance of preferred stock	70,035	0	0
Issuance of common stock	0	0	73,765
Payment of preferred stock dividends	-4,627	0	0
Taxes paid related to exercise of employee stock options	0	-18	0
Net cash provided by (used in) financing activities	27,348	-243	38,703
Net change in cash and cash equivalents	1,873	-42,656	26,359
Balance, beginning of period	1,139	43,795	17,436
Balance, end of period	$3,012	$1,139	$43,795

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (Senior Notes [Member], 13% Senior Notes due 2016 [Member])	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Senior Notes [Member] | 13% Senior Notes due 2016 [Member]	'	'	'	'
Debt instrument, interest rate, stated (as a percent)	13.00%	13.00%	13.00%	13.00%

Description_of_Business_and_Ba

Description of Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Description of Business and Basis of Presentation	'
	Description of Business and Basis of Presentation
	Callon Petroleum Company is an independent oil and natural gas company established in 1950, which has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. In 2013, the Company completed the onshore strategic repositioning it initiated in 2009, shifting its operations from the offshore waters in the Gulf of Mexico to the Permian Basin region in Texas. The Company has built seasoned technical and operational teams with extensive experience in the Permian Basin to manage and progress its growth plan. In the fourth quarter of 2012, Callon sold its interest in its deepwater Habanero field. Similarly, in the fourth quarter of 2013, the Company sold its interest in its only remaining deepwater property, the Medusa field, including the sale of the Medusa Spar facility and substantially all remaining offshore shelf properties. These transactions completed the Company’s long-term strategic goal of becoming an onshore operator with an asset base concentrated in the Permian Basin.
	The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management.  As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
	The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”).  CPOC also includes the subsidiaries Callon Offshore Production, Inc. and Mississippi Marketing, Inc.  All intercompany accounts and transactions have been eliminated.  Certain prior year amounts have been reclassified to conform to presentation in the current year.  To the extent these amounts are material, we have either footnoted them within the Company’s disclosures or have noted the items within this footnote. The Company reclassified on its 2012 and 2011 Consolidated Statements of Operations $3,224 and $2,062, respectively, from “Lease operating expenses” to “Production taxes” to conform to current year presentation.
	Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	A.	Use of Estimates
	The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of 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.
	B.	Cash and Cash Equivalents
	The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
	C.	Accounts Receivable
	Accounts receivable consists primarily of accrued oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $73 and $34 at December 31, 2013 and 2012, respectively. During 2013, 2012, and 2011 the Company recorded $45, $0 and $(281), respectively of bad debt expense. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt expense during 2010.
	D.	Revenue Recognition and Natural Gas Balancing
	The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables were $71 and $93 as of 2013 and 2012, respectively. Natural gas balancing payables were $126 and $653 as of 2013 and 2012, respectively.
	E.	Major Customers
	The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a greater than 10% of its total oil and natural gas production during each of the years ended:
		For the Year Ended December 31,
		2013		2012		2011
	Enterprise Crude Oil, LLC	38	%	32	%	16	%
	Shell Trading Company	31	%	39	%	45	%
	Plains Marketing, L.P.	15	%	15	%	17	%
	Other	16	%	14	%	22	%
	Total	100	%	100	%	100	%
	Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and natural gas production.
	F.	Oil and Natural Gas Properties
	The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $14,753, $13,331 and $11,857 of these internal costs during 2013, 2012 and 2011, respectively.
	When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income.
	Costs of oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.
	Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. See Note 12 for additional information regarding the Company’s oil and natural gas properties.
	Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data.  Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC’s rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.
	G.	Other Property and Equipment
	The Company depreciates its other property and equipment of $7,255 and $6,424 at December 31, 2013 and 2012, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $750, $760 and $645 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011, respectively. The accumulated depreciation on other property and equipment was $13,240 and $13,238 as of December 31, 2013 and 2012, respectively. As discussed in Note 13, during 2013, the Company recorded an impairment charge to reduce to zero the carrying values of its assets held for sale. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
	H.	Capitalized Interest
	The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization (e.g. unevaluated properties). Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2013, 2012 and 2011, the Company capitalized $4,410, $2,109 and $573 of interest expense.
	I.	Asset Retirement Obligations
	The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 11 for additional information.
	J.	Derivatives
	The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges were recognized as derivative expense (income). The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 2013 and outstanding as of December 31, 2013 were not designated as accounting hedges, and are carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts. See Notes 5 and 6 for additional information regarding the Company’s derivative contracts.
	K.	Income Taxes
	Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which it is deemed more likely than not that it will not be realized. See Note 10 for additional information.
	L.	Share-Based Compensation
	The Company grants to directors and employees stock options, restricted stock awards (“RS awards”), and restricted stock unit awards (“RSU awards”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”).
	Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years).
	RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years).
	M.	Statements of Cash Flows Supplemental Information
	During the three year period ended 2013, the Company paid no federal income taxes. During the years ended December 31, 2013, 2012 and 2011, the company made cash interest payments of $13,189, $13,920 and $14,922, respectively.
	N.	Investment in Medusa Spar LLC
	During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field, its 10.0% membership interest in Medusa Spar LLC (“LLC”), and substantially all of its remaining Gulf of Mexico shelf properties. Prior to the sale, the Company’s ownership interest in the LLC was accounted for under the equity method of accounting for investments. The LLC held a 75% undivided ownership interest in the deepwater spar production facilities at the Medusa field in the Gulf of Mexico and earned a tariff based upon production volume throughput from the Medusa area. The Company was obligated to process through the spar production facilities its share of production from the Medusa field and any future discoveries in the area. The balance of the LLC was owned by Oceaneering International, Inc. and Murphy Oil Corporation. See Note 12 for additional information on the Medusa divestiture.
	O.	Consolidation of Variable Interest Entities
	In June 2009, the FASB issued an accounting standard which became effective for and was adopted by the Company on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, which resulted in Callon gaining the power to direct the activities of Callon Entrada, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company’s financial statements. Callon Entrada was later dissolved in 2011.
	P.	Earnings per Share (EPS)
	The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period.  Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares.
	Q.	Recent Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
	In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requires that the Company present either on the face of its financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, the Company is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.

Earnings_loss_per_Share

Earnings (loss) per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings (loss) per Share	'
	Earnings (loss) per Share
	Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised options outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):
		For the year ended December 31,
		2013			2012		2011
	Net income	$	4,304		$	2,747	$	106,396
	Preferred stock dividends	(4,627		)	—		—
	(a) Income (loss) available to common shareholders	$	(323	)	$	2,747	$	106,396
	(b) Weighted average shares outstanding	40,133			39,522		37,908
	Dilutive impact of stock options	—			8		18
	Dilutive impact of restricted stock	—			807		656
	(c) Weighted average shares outstanding
	for diluted net income (loss) per share (1)	40,133			40,337		38,582
	Basic Income (loss) per share (a/b)	$	(0.01	)	$	0.07	$	2.81
	Diluted Income (loss) per share (a/c)	$	(0.01	)	$	0.07	$	2.76
	The following were excluded from the diluted EPS calculations because their effect would be anti-dilutive:
	Stock options	52			52		67
	Restricted stock	398			123		816
	-1	Because the Company reported a loss for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive.

Borrowings

Borrowings	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Borrowings	'
	Borrowings
		For the year ended December 31,
		2013			2012
	Principal components:
	Credit Facility	$	22,000		$	10,000
	13% Senior Notes due 2016, principal	48,481			96,961
	Total principal outstanding	$	70,481		$	106,961
	Non-cash components:
	13% Senior Notes due 2016 unamortized deferred credit	5,267			13,707
	Total carrying value of borrowings	$	75,748		$	120,668
	Senior Secured Revolving Credit Facility (the “Credit Facility”)
	The Company’s $200,000 Credit Facility, for which Regions Bank serves as the Administrative Agent, matures March 15, 2016 and includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. The Company’s Credit Facility had an approved borrowing base at December 31, 2013 of $83,000. The Credit Facility was secured by mortgages covering the Company’s major producing fields. As of December 31, 2013, the balance outstanding on the Credit Facility was $22,000 with an interest rate of 2.92%, calculated as the London Interbank Offered Rate (LIBOR), plus a tiered rate ranging from 2.5% to 3.0%, which is determined by utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.
	Subsequent to December 31, 2013, the Company amended its existing Credit Facility as discussed below. Additionally, the Company executed the Second Lien Facility also discussed below.
	Amended Credit Facility (“the Amended Credit Facility”)
	On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement million with JPMorgan Chase Bank, National Association as Administrative Agent.
	The Amended Credit Facility includes the following key provisions:
	•	$500,000 notional amount, with an initial borrowing base of $95,000;
	•	Maturity date of March 11, 2019;
	•	First redetermination scheduled with an effective date of May 30, 2014, with subsequent redeterminations occurring every six months beginning on September 1, 2014;
	•	Pricing grid providing from Eurodollar-based draws ranging from LIBOR plus 1.75% to 2.75% depending on utilization;
	•	A quarterly commitment fee equal to 0.5% per year of the unused portion of the borrowing base; and
	•	Secured by mortgages covering all major producing fields.
	The Amended Credit Facility contains various affirmative and restrictive covenants.
	Second Lien Term Loan Facility (the “Second Lien Facility”)
	In conjunction with the Amended Credit Facility, the Company entered into the Second Lien Facility in an aggregate amount of up to $125,000 with JPMorgan Chase Bank, National Association as Administrative Agent. The Second Lien Facility is structured as a multiple advance term loan facility, with initial commitments of $100,000. If any portion of the committed Second Lien Facility remains undrawn on the first anniversary of the closing date, then the unfunded commitments under the Second Lien Facility, if any, will terminate on such date.
	The Second Lien Facility includes the following key provisions:
	•	$125,000 master note, with initial commitments $100,000 and additional availability of $25,000 with consent of 66 2/3% of the lenders and compliance with financial covenants after giving effect to such increase;
	•	Maturity date of September 11, 2019;
	•	No mandatory prepayments unless new debt is issued;
	•	Prepayable at any time. The prepayment premium shall be applicable to the amount of the applicable prepayment multiplied by (i) 102% if such prepayment event occurs prior to the first anniversary of the Closing Date and (ii) 101% if such prepayment event occurs on or after the first but prior to the second anniversary of the Closing Date. No such prepayment premium shall be payable for prepayments made on or after the second anniversary of the closing date;
	•	Interest expense at a rate of LIBOR plus 7.75%, calculated on a per annum basis;
	•	A commitment fee equal to 0.5% calculated on a per annum basis on the unused portion of the initial commitment amount until March 11, 2015;
	•	The amounts funded on the initial draw date shall be issued with an original issue discount of 1.00% and each subsequent draw shall be subject to the same 1.00% original issue discount on the drawn amount, applied on the date such draw is funded; and
	•	Secured by junior liens on properties mortgaged under the Amended Credit Facility, subject to an intercreditor agreement.
	The Second Lien Facility contains various affirmative and restrictive covenants.
	13% Senior Notes due 2016 (the “Senior Notes”) and Deferred Credit
	As of December 31, 2013, the Company had principal outstanding of $48,481 related to its 13% Senior Notes. The interest coupon is payable on the last day of each quarter. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the unsecured Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors are minor. Upon issuing the Senior Notes in November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527.  The $31,507 difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction in interest expense over the life of the Senior Notes at an 8.5% effective interest rate.
	The following table summarizes the Company’s deferred credit balance at December 31, 2013:
	Gross Carrying		Accumulated Amortization at	Carrying Value at		Amortization Recorded during Current Year	Estimated Annual Amortization Expense Expected to be Recognized in
	Amount		December 31, 2013	December 31, 2013		(a)	2014
	$31,507		$26,240	$5,267		$8,440	$5,267
	(a)	Of the amount recorded as amortization during the current year, $3,165 was recorded as a reduction of interest expense and $5,275 (discussed below) was recorded as a component of the gain on early extinguishment of debt.
	Using a portion of the proceeds from the sale of our interest in Medusa on December 17, 2013, the Company redeemed $48,481 of its Senior Notes, which resulted in a net $3,696 gain on the early extinguishment of debt. The gain represents the difference between the $50,057 paid (inclusive of $1,576 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $53,756 (inclusive of the $5,275 of accelerated deferred credit amortization).
	In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a net $1,366 gain on the early extinguishment of debt. The gain represents the difference between the $10,225 paid (inclusive of $225 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $11,591 (inclusive of the $1,591 of accelerated deferred credit amortization).
	In March 2011, the Company redeemed $31,000 of its Senior Notes using proceeds from its February 2011 equity offering, which resulted in a $1,974 gain on the early extinguishment of debt. The gain represents the difference between the $35,062 paid (inclusive of the$4,062 of redemption expenses, primarily the call premium) for Senior Notes with a carrying value of $37,004 (inclusive of the $6,004 of accelerated deferred credit amortization).
	On March 11, the Company provided notice to holders of its outstanding Senior Notes that it expects to redeem those notes on April 11, 2014 using proceeds from the previously discussed Second Lien Facility. The redemption will result in the acceleration of the amortization of the remaining $5,267 of deferred credit as reflected in the table above.
	Restrictive Covenants
	The Indenture governing our Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2013.

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments and Hedging Activities	'
	Derivative Instruments and Hedging Activities
	Objectives and Strategies for Using Derivative Instruments
	The Company is exposed to fluctuations in oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes primarily a mix of collar, swap, put and call derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
	Counterparty risk and offsetting
	The use of derivative transactions exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. Counterparty credit risk is considered when determining a derivative instruments’ fair value; See Note 6 for additional information regarding fair value.
	The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
	Financial statement presentation and settlements
	Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (“NYMEX”) price. The fair value of the Company’s derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.
	Beginning in 2012, the Company elected not to designate its executed derivative contracts, nor does it expect to designate future derivative contracts, as an accounting hedge under FASB ASC 815. Consequently, any derivative contract not designated as an accounting hedge will be carried at its fair value on the balance sheet and marked-to-market at the end of each period, with the change in value reflected as a gain or loss on the statement of operations. Gains and losses on derivatives that are not designated as hedges are recorded in earnings as a component of gain (loss) on derivative contracts. Within the gain (loss) on derivative contracts line of the statement of operations are gains (losses) on derivatives, net of settlement and gains (losses) on derivatives, settled.
	Prior to 2012, the Company’s derivative contracts recorded on the Consolidated Balance Sheets were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through OCI in stockholders’ equity. The cash settlements on effective derivative contracts were recorded as an increase or decrease in oil and natural gas sales.
	The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
			Balance Sheet Presentation				Asset Fair Value								Liability Fair Value						Net Derivative Fair Value
	Commodity		Classification		Line Description		12/31/13				12/31/12				12/31/13			12/31/12			12/31/13			12/31/12
	Derivatives not designated as Hedging Instruments under ASC 815
	Natural gas		Current		Fair market value of derivatives		$	60			$	—			$	—		$	(125	)	$	60		$	(125	)
	Natural gas		Non-current		Other long-term liabilities		—				—				(72		)	(116		)	(72		)	(116		)
	Oil		Current		Fair market value of derivatives		—				1,674				(1,036		)	—			(1,036		)	1,674
	Oil		Non-current		Other long-term assets		—				250				—			—			—			250
			Totals				$	60			$	1,924			$	(1,108	)	$	(241	)	$	(1,048	)	$	1,683
	The Company’s derivative contracts are subject to netting arrangements and, being representative of the way in which the contracts settle, are presented in the balance sheet at their fair values on a net basis based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at December 31, 2013:
			Presented without								As Presented with
			Effects of Netting				Effects of Netting				Effects of Netting
	Current assets: Fair value of hedging contracts		$	8			$	52			$	60
	Long-term assets: Fair value of hedging contracts		—				—				—
	Current liabilities: Fair value of hedging contracts		1,088				(52		)		1,036
	Long-term liabilities: Fair value of hedging contracts		(72		)		—				(72		)
	Derivatives not designated as hedging instruments under ASC 815
	For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges and are recorded in the Statement of Operations as gain or loss on derivative contracts:
		For the year ended December 31,
		2013				2012				2011
	Natural gas derivatives
	Net (loss) gain on derivatives, settled	$	(147	)		$	34			$	—
	Net gain (loss) on derivatives, net of settlements	229				(241		)		—
	Subtotal gain (loss), net	$	82			$	(207	)		$	—
	Oil derivatives
	Net gain, on derivatives, settled	$	1,518			$	—			$	—
	Net (loss) gain on derivatives, net of settlements	(2,960		)		1,924				—
	Subtotal (loss) gain, net	$	(1,442	)		$	1,924			$	—
	Total (loss) gain on derivative instruments included in Statement of Operations	$	(1,360	)		$	1,717			$	—
	Derivatives designated as hedging instruments under ASC 815
	The table below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and natural gas sales for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
		For the year ended December 31,
		2013				2012				2011
	Amount of gain (loss) reclassified from OCI into income (effective portion)	$	—			$	1,420			$	(375	)
	Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)	—				—				—
	Derivative positions
	In the first quarter of 2013, the Company monetized the remaining portion of its 2013 oil collar positions (for the period February - December 2013) of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the oil swap for the period February - December 2013.
	Listed in the table below are the outstanding oil and natural gas derivative contracts as of December 31, 2013:
	Commodity		Instrument		Average Notional Volumes per Month		Quantity Type		Put/Call Price				Fixed-Price Swap				Period	Designation under ASC 815
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Jan14 - Mar14	Not Designated
	Natural gas		Swap		60		MMBtu		n/a				$	4.36			Jan14 - Mar14	Not Designated
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Jan14 - Dec14	Not Designated		(a)
	Oil		Swap		30		Bbls		n/a				$	93.35			Jan14 - Dec14	Not Designated
	Oil		Put Option		30		Bbls		$	70			n/a				Jan14 - Dec14	Not Designated
	Oil		Swap		9		Bbls		n/a				$	94.58			Jan14 - Dec14	Not Designated
	Natural gas		Swap		46		MMBtu		n/a				$	4.25			Apr14 - Dec14	Not Designated
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Apr14 - Dec14	Not Designated
	Natural gas		Call Option		37		MMBtu		$	5			n/a				Jan15 - Dec15	Not Designated
	(a)	The short natural gas call option, when combined with the Company’s long production position, represents a “covered call,” and creates a $4.75/MMbtu ceiling during the covered period.
	Subsequent Event Activity:
	Derivative contracts executed subsequent to December 31, 2013 include the following:
	Commodity		Instrument		Average Notional Volumes per Month		Quantity Type		Put/Call Price		Fixed-Price Swap				Period		Designation under ASC 815
	Oil		Swap		15		Bbls		n/a		$	94.15			Feb14 - Mar14		Not Designated
Oil		Swap		15		Bbls		n/a		$	92.8			Apr14 - Jun14		Not Designated
Oil		Swap		15		Bbls		n/a		$	90.4			Jul14 - Sep14		Not Designated
Oil		Swap		15		Bbls		n/a		$	88.64			Oct14 - Dec14		Not Designated

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	Fair value is defined within the accounting rules 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. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
	Level 1	Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority.
	Level 2	Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability.
	Level 3	Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.
	Fair Value of Financial Instruments
	Cash, Cash Equivalents, and Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
	Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.
	The following table summarizes the respective carrying and fair values at:
		For the year ended December 31,
		2013						2012
		Carrying Value			Fair Value			Carrying Value			Fair Value
	Credit Facility	$	22,000		$	22,000		$	10,000		$	10,000
	13% Senior Notes due 2016 (a)	53,748			50,299			110,668			100,112
	Total	$	75,748		$	72,299		$	120,668		$	110,112
	(a)	2013 and 2012 fair values are calculated only in relation to the $48,481 and $96,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $5,267 and $13,707, respectively represents the Company’s deferred credits and have been excluded from the fair value calculation. See Note 4 for additional information.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
	Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 5 for additional information regarding the Company’s derivative instruments.
	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
	December 31, 2013		Balance Sheet Presentation	Level 1			Level 2			Level 3			Total
	Assets
	Derivative financial instruments - current Portion		Fair market value of derivatives	$	—		$	60		$	—		$	60
	Derivative financial instruments - non-current		Other assets, net	—			—			—			—
	Sub-total assets			$	—		$	60		$	—		$	60
	Liabilities
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	1,036		$	—		$	1,036
	Derivative financial instruments - non-current		Other long-term liabilities	—			72			—			72
	Sub-total liabilities			$	—		$	1,108		$	—		$	1,108
	Total			$	—		$	(1,048	)	$	—		$	(1,048	)
	December 31, 2012		Balance Sheet Presentation	Level 1			Level 2			Level 3			Total
	Assets
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	1,674		$	—		$	1,674
	Derivative financial instruments - non-current		Other assets, net	—			250			—			250
	Sub-total assets			$	—		$	1,924		$	—		$	1,924
	Liabilities
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	125		$	—		$	125
	Derivative financial instruments - non-current		Other long-term liabilities	—			116			—			116
	Sub-total liabilities			$	—		$	241		$	—		$	241
	Total			$	—		$1,683			$	—		$1,683
	The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the Consolidated Balance Sheet at December 31, 2013.
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:
	Other Property and Equipment. As discussed in Note 13, the Company’s decision to abandon certain of its other property and equipment, that had been classified as held for sale, resulted in an impairment charge of $1,707 which is included in the Company’s Statement of Operations for the year ended December 31, 2013. The impairment charge was valued using level 3 inputs.
	Acquisition. During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin for a purchase price of $11,000. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The Company valued the acquired assets in accordance with the method described below. In accordance with the acquisition method of accounting, the purchase price of the Company’s acquisition during the period has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. In valuing the acquired assets and liabilities assumed, fair values were based on expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. The purchase price of the Company’s acquisition during the period was $11,000 with approximately $2,000 allocated to unevaluated oil and gas properties and approximately $9,000 allocated to evaluated oil and gas properties. Asset retirement obligations assumed in connection with the transaction were insignificant due to the nature of the properties acquired. The unaudited pro forma results of the properties acquired are immaterial to the Company’s financial statements. The fair value measurements were based on significant inputs not observable in the market and thus represent a level 3 measurement.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 8. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
	Savings and Protection Plan
	The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $923, $918 and $811 in the years 2013, 2012 and 2011, respectively.
	2011 Omnibus Incentive Plan (the “2011 Plan”)
	The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841 shares into the plan, increasing the quantity authorized and reserved for issuance under the Plan to 3,141 at the inception of the plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. As of December 31, 2013, the 2011 Plan had 1,192 shares remaining and eligible for future issuance.
	Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may be immediate or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded.
	Cash-Settleable RSU Awards
	Certain of the Company’s RSUs awarded require cash-settlement. Cash-settleable RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash, and are recorded in the Company’s consolidated balance sheet for the ratable portion of their fair values. The fair value of the Company’s market-based RSU is calculated using a Monte Carlo valuation model, which considers such inputs as the Company’s and its peer group’s stock prices, a risk-free interest rate, and an estimated volatility for the Company and its peer group. Changes in the fair value of cash-settleable awards are recorded as adjustments to compensation expense.
	Market-based RSUs: A significant portion of the Company’s cash-settleable RSU awards include a market-based vesting condition and may ultimately vest at a quantity different than the base RSUs awarded. The number of RSUs that cliff-vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded.
	As of December 31, 2013, the Company had the following cash-settleable RSU awards outstanding (including those that are not based on a market condition):
		Base Units	Potential Minimum	Potential Maximum
		Outstanding at	Units at Vesting at	Units at Vesting at
	Vesting in 2014	510	45	975
	Vesting in 2015	909	60	1,758
	Vesting in 2016	66	66	66
	Other	92	92	92
	Total cash-settleable RSU awards	1,577	263	2,891
	For the year ended December 31, 2013, 260 market-based cash-settleable RSUs subject to the peer market-based vesting described above vested at 100% of their issued units, resulting in a cash payment of $1,669. Also during 2013, 65 non-market-based cash settleable RSUs vested, resulting in a cash payment of $239. During 2012, 364 market-based cash-settleable RSUs vested at 150%, resulting in a cash payment of $2,626. Also during 2012, 143 non-market-based cash settleable RSUs vested, resulting in a cash payment of $763. See Note 8 for additional information regarding cash-settleable RSUs.

ShareBased_Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Share-Based Compensation	'
	Share-Based Compensation
	As discussed in Note 7, the Company grants various forms of share-based compensation awards to employees of the Company and its subsidiaries and to non-employee members of the Board of Directors. At December 31, 2013, shares available for future share-based awards, including stock options or restricted stock grants, under the Company’s only active plan, the 2011 Plan, were 1,192.
	The following table presents share-based compensation expense for each respective period:
		For the year ended December 31,
		2013								2012					2011
	Share-based compensation expense for:	Equity-based				Liability-based				Equity-based			Liability-based		Equity-based		Liability-based
	Options	$	—			$	—			$	—		$	—	$	24	$	—
	RSU equity awards	3,975				—				4,210			—		2,832		—
	Cash-settleable RSU awards	—				5,347				—			2,916		—		1,335
	401(k) contributions in shares	219				—				218			—		202		—
	Total share-based compensation expense (a)	$	4,194			$	5,347			$	4,428		$	2,916	$	3,058	$	1,335
	(a)	The portion of this share-based compensation expense that was included in general and administrative expense totaled $5,751, $4,081 and $2,502 for the same years respectively, and the portion capitalized to oil and gas properties was $3,791, $3,263 and $1,891, respectively.
	The following table presents the specified share-based compensation expense for the indicated periods:
		For the year ended December 31,
	Unrecognized compensation costs related to:	2013			2012			2011
	Unvested RSU equity awards	5,331			6,320			5,748
	Unvested cash-settleable RSU awards	7,669			2,826			2,498
	The Company’s future expected share-based compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.4 years.
	The following table summarizes the Company’s cash-settleable RSU awards for the periods indicated:
	Consolidated Balance Sheets Classification		2013				2012				2011
	Accounts payable and accrued liabilities - current portion		$	4,173			$	1,429			$	604
	Other long-term liabilities - non-current portion		3,409				1,017				2,309
	Total cash-settleable RSU awards		$	7,582			$	2,446			$	2,913
	Stock Options
	The Company issued no stock options for the past three years and had no options vest or forfeit during 2013. Additionally, no options were exercised, 15 options expired unexercised during the year. As of December 31, 2013, the Company had 52 options outstanding and exercisable at a weighted average exercise price per option of $13.75, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.3 years.
	As of December 31, 2012, the Company had 67 options outstanding and exercisable at a weighted average exercise price per option of $11.82, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 2.7 years. The Company net-share settles option exercises and therefore receives no cash proceeds from the exercise of stock options.
	Restricted Stock Units
	The following table represents unvested restricted stock activity for the year ended December 31, 2013:
		Weighted average
		Number of Shares			Grant-Date Fair Value per Share				Period over which expense is expected to be recognized
	Outstanding at the beginning of the period	2,295			$	5.58
	Granted	944			3.82
	Vested (a)	(754	)		5.1
	Forfeited	(223	)		5.37
	Outstanding at the end of the period	2,262			$	5.03			1.5
	a.	The fair value of shares vested was $2,689.

Equity_Transactions

Equity Transactions	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Equity Transactions	'
	Equity Transactions
	On May 30, 2013, the Company issued 78,947 of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70,035 net proceeds after deducting the underwriting commissions and offering expenses. The sale consisted of 1,579 shares of Preferred Stock, par value $0.01 per share, public offering price of $47.50 per share and liquidation preference of $50.00 per share in an underwritten public offering. The Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation or dissolution. The Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund. The Preferred Stock will remain outstanding indefinitely unless repurchased by the Company or converted into Callon common stock in connection with certain changes in control as defined in the Preferred Stock prospectus.
	Holders of the Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors (the “Board”), out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board. The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on June 28, 2013 (as June 30 fell on a weekend) in the amount of $0.43 per share or $679 for the stub period beginning with the issuance on May 30, 2013 through the dividend date on June 30, 2013. For the subsequent quarters ended September 30 and December 31, 2013, the Board of Directors declared for each quarter a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock, resulting in total dividend expense recognized in 2013 of $4,627.
	Beginning on May 30, 2018, the Company may, solely at its option, redeem the Preferred Stock in whole at any time, or in part from time to time, for cash at a redemption price of $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. The Company may redeem the Preferred Stock following certain changes of control as defined in the Preferred Stock prospectus, in whole or in part, within 120 days after the date on which the change of control has occurred, for cash at $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company elects not to exercise this option, the holders of the Preferred Stock have the option to convert each share of Preferred Stock into a predefined number of Company common shares, subject to certain adjustments.
	As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. Based on the Company’s 60,000 authorized shares at December 31, 2013, 16,800 shares were reserved for a potential conversion. Subsequent to December 31, 2013, via a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000 to 110,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200 shares. Based on the Company’s closing common stock price of $6.53 per share on December 31, 2013, the Company reserved 12,090 shares to satisfy the potential conversion.
	Except as required by law, holders of the Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the Board, which will increase in size by that same number of directors.
	During February, 2011, the Company received $73,765 in net proceeds from the public offering of 10.1 million shares of its common stock, which included the issuance of 1.1 million shares pursuant to the underwriters’ over-allotment option. The Company used $35,062 of the proceeds to repurchase $31,000 principal amount of its Senior Notes, with the remaining proceeds intended for general corporate purposes including the planned development of the Company’s Permian basin and other onshore assets.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations:
		For the Year Ended December 31
		2013				2012
	Deferred tax asset
	Federal net operating loss carryforward	$	70,365			$	87,774
	Statutory depletion carryforward	8,880				8,184
	Alternative minimum tax credit carryforward	208				208
	Asset retirement obligations	1,024				3,357
	Other	7,575				9,571
	Total deferred tax asset	88,052				109,094
	Deferred tax liability
	Oil and natural gas properties	26,412				41,336
	Other	32				3,375
	Total deferred tax liability	26,444				44,711
	Net deferred tax asset	$	61,608			$	64,383
	Prior to 2012, the Company carried a full valuation allowance against its net deferred tax assets. The Company considered both the positive and negative evidence in determining whether it was more likely than not that its deferred tax assets were recoverable. The Company incurred a loss in 2008, primarily as a result of a write-down of its oil and natural gas properties following the ceiling test, which created a loss on an aggregate basis for the three-year period ended December 31, 2008. Primarily as a result of recent cumulative losses, the Company established a full valuation allowance as of December 31, 2008, and continued to carry the full valuation allowance each reporting period until December 31, 2011. At December 31, 2011, after considering all available positive and negative evidence, including the Company’s profitable operations from 2009 to 2011 which resulted in income on an aggregate basis for the three year period ended December 31, 2011, and future operating results based on proved reserves, the Company determined that it was more likely than not that it would fully utilize its deferred tax assets recorded at December 31, 2011. Therefore, the Company reversed its valuation allowance at December 31, 2011.
	If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
							Year Expiring
			Total				2014-2019			2020-2022			2023-2025		2026-2028		2029-2033
	Federal NOL carryforwards		$	201,042			$	—		$	48,986		$	65,878	$	32,714	$	53,464
	The Company has limited state taxable income. Accordingly, the Company has established a full valuation allowance on the tax benefits associated with the state net operating loss carryforwards of approximately$167,795 which expire in years through 2033, as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply. These amounts are not included in the deferred tax summary table above.
	In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties. This shift in exploration and development activity resulted in an increase in Texas income from production. This, coupled with the Company’s exit from the Gulf of Mexico (the sale of its interest in the Habanero field in December 2012 and the Medusa field in December 2013), results in a change in the projected future Texas state tax rate beyond 2013 as a component of overall anticipated future taxes.
	The Company had no significant unrecognized tax benefits at December 31, 2013. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2001 through 2013 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.
	Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations.
			For the Years Ended December 31,
	Component of Income Tax Rate Reconciliation		2013				2012			2011
	Income tax expense computed at the statutory federal income tax rate		35		%		35		%	35		%
	Change in valuation allowance		—		%		—		%	(227		)%
	Percentage depletion carryforward		(8		)%		(22		)%	(3		)%
	State taxes net of federal benefit		4		%		6		%	—		%
	Restricted stock and stock options		5		%		2		%	—		%
	Section 162(m)		6		%		22		%	—		%
	Other		—		%		4		%	4		%
	Effective income tax rate		42		%		47		%	(191		)%
			For the Years Ended December 31,
	Components of Income Tax Expense		2013				2012			2011
	Current federal income tax benefit		$	—			$	—		$	—
	Current state income tax expense		326				110			—
	Deferred federal income tax expense		2,652				1,777			13,176
	Deferred state income tax expense		126				336			—
	Valuation allowance		—				—			(82,459		)
	Total income tax expense (benefit)		$	3,104			$	2,223		$	(69,283	)

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The following table summarizes the activity for the Company’s asset retirement obligations:
		For the Year Ended December 31,
		2013			2012
	Asset retirement obligations at beginning of the period	$	13,301		$	13,938
	Accretion expense	1,785			2,253
	Liabilities incurred	679			205
	Liabilities settled	(457		)	(1,073		)
	Liabilities related to oil and gas properties sold	(4,765		)	(877		)
	Revisions to estimate	(3,811		)	(1,145		)
	Asset retirement obligations at end of period	6,732			13,301
	Less: current asset retirement obligations	(4,120		)	(2,336		)
	Long-term asset retirement obligations at the end of the period	$	2,612		$	10,965
	Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets at December 31, 2013 as long-term restricted investments were $3,806. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
	On December 5, 2013, the Company closed on its agreement to sell its interest in the Medusa field, Medusa Spar LLC, and substantially all of its Gulf of Mexico shelf properties to W&T Offshore, Inc. (“W&T”). Under the agreement, W&T will assume an estimated $4,765 of the ARO related to these offshore assets.
	The Company’s total revisions to estimates of $3,811 for the year ended December 31, 2013 relate to downward revisions related to the changes in the expecting timing of the abandonment.

Supplemental_Oil_and_Natural_G

Supplemental Oil and Natural Gas Reserve Data (unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Supplemental Oil and Natural Gas Reserve Data (unaudited)	'
	Supplemental Information on Oil and Natural Gas Operations (Unaudited)
	Oil and Natural Gas Properties
	The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
		For the Year Ended December 31,
	Capitalized costs incurred:	2013				2012				2011
	Evaluated Properties-
	Beginning of period balance	$	1,497,010			$	1,421,640			$	1,316,677
	Capitalized G&A	10,014				12,148				11,205
	Property acquisition costs	10,885				2,075				—
	Exploration costs	147,164				22,703				5,473
	Development costs	36,504				38,444				88,285
	End of period balance	$	1,701,577			$	1,497,010			$	1,421,640
	Unevaluated Properties (excluded from amortization):
	Beginning of period balance	$	68,776			$	2,603			$	8,106
	Acquisitions	2,259				29,590				2,422
	Exploration	10,767				34,674				1,372
	Capitalized interest	4,410				2,109				573
	Transfers to evaluated	(42,990		)		(200		)		(9,870		)
	End of period balance	$	43,222			$	68,776			$	2,603
	Accumulated depreciation, depletion and amortization:
	Beginning of period balance	$	1,296,265			$	1,208,331			$	1,155,915
	Provision charged to expense	42,251				48,524				52,416
	Sale of mineral interests	82,096				39,410				—
	End of period balance	$	1,420,612			$	1,296,265			$	1,208,331
	Unevaluated property costs primarily include lease acquisition costs incurred at federal lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. The Company’s unevaluated property balance decreased by $25,554 to $43,222 at December 31, 2013 compared to December 31, 2012. A significant portion of this decrease relates to the transfer of drilling and completion costs from the unevaluated property base to the evaluated property base.
	Subsequent to December 31, 2013 and through March 10, 2014, the Company completed six horizontal exploration wells, drilled four horizontal wells and had two in progress. Additionally, the Company drilled two vertical exploratory wells and will be evaluating the results.
	Depletion per unit-of-production (BOE) amounted to $31.12, $31.56 and $26.42 for the years ended December 31, 2013, 2012, and 2011, respectively. Lease operating expense per unit-of-production (BOE) amounted to $14.00, $14.81, and $9.92 for the years ended December 31, 2013, 2012, and 2011, respectively.
	Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. For the years ended December 31, 2013, 2012, and 2011, the Company recorded no impairment charges related to its oil and natural gas properties as a result of this calculation.
	Estimated Reserves
	The Company’s proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers.  The reserves were prepared in accordance with guidelines established by the SEC.  Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
	There are numerous uncertainties inherent in establishing quantities of proved reserves.  The following reserve data represents estimates only, and should not be deemed exact.  In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
	Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows:
		Reserve Quantities
		For the year ended December 31,
		2013			2012			2011
	Proved developed and undeveloped reserves:
	Oil (MBbls):
	Beginning of period	10,780			10,075			8,149
	Revisions to previous estimates	(2,540	)		(488	)		(110	)
	Purchase of reserves in place	150			38			—
	Sale of reserves in place	(3,294	)		(504	)		(30	)
	Extensions and discoveries	7,713			2,636			3,062
	Production	(911	)		(977	)		(996	)
	End of period	11,898			10,780			10,075
	Natural Gas (MMcf):
	Beginning of period	19,753			35,118			32,957
	Revisions to previous estimates	(5,351	)		(10,838	)		486
	Purchase of reserves in place	317			115			—
	Sale of reserves in place	(4,576	)		(4,404	)		(308	)
	Extensions and discoveries	10,619			3,350			7,064
	Production	(3,011	)		(3,588	)		(5,081	)
	End of period	17,751			19,753			35,118
	Proved developed reserves:
	Oil (MBbls):
	Beginning of period	4,955			5,069			4,503
	End of period	5,960			4,955			5,069
	Natural Gas (MMcf):
	Beginning of period	10,680			11,605			12,715
	End of period	9,059			10,680			11,605
	MBOE:
	Beginning of period	6,735			7,003			6,622
	End of period	7,470			6,735			7,003
	Proved undeveloped reserves:
Oil (MBbls):
Beginning of period	5,825			5,006			3,645
End of period	5,938			5,825			5,006
Natural Gas (MMcf):
Beginning of period	9,073			23,513			20,241
End of period	8,692			9,073			23,513
MBOE
Beginning of period	7,337			8,925			7,019
End of period	7,387			7,337			8,925
Total Proved Reserves: The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase is primarily due the Company’s development of its Permian basin, on which it drilled a total of 26 oil wells during 2013. The increase is offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.
Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs.  The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions.  Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The Company’s PUDs increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by the reclassification of 3,724 MBOE, or 51%, included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to the horizontal probable, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include Wolfberry PUD locations that included certain target zones that are now expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells.
The Company’s PUDs decreased 18% to 7,337 MBOE from 8,925 MBOE at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBOE to the Company’s PUDs, offset by (1) 557 MBOE primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBOE related to the sale of Habanero, and (3) 2,227 MBOE related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company’s year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net.
Of the Company’s 2012 PUDs, 1,297 MBOE were attributable to the Company’s offshore properties in the Medusa field in the Gulf of Mexico. As previously noted, the Company sold its interest in the Medusa field during 2013.
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2013. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
		2013				2012				2011
Average 12-month price, net of differentials, per Mcf of natural gas		$	5.45			$	4.81			$	5.6
Average 12-month price, net of differentials, per barrel of oil		$	92.16			94.68				98.98
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
Natural gas production from our deepwater and Permian Basin properties has a high Btu content of separator natural gas. The natural gas Mcf prices of $5.45 and $4.81 used in the 2013 and 2012 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices of $92.16 and $94.68 used in the 2013 and 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
	Standardized Measure
	For the year ended December 31,
	2013				2012				2011
Future cash inflows	$	1,193,299			$	1,115,570			$	1,194,079
Future costs -
Production	(357,005		)		(249,329		)		(356,653		)
Development and net abandonment	(155,667		)		(273,817		)		(268,628		)
Future net inflows before income taxes	680,627				592,424				568,798
Future income taxes	(68,239		)		(55,772		)		(78,813		)
Future net cash flows	612,388				536,652				489,985
10% discount factor	(328,442		)		(305,504		)		(219,628		)
Standardized measure of discounted future net cash flows	$	283,946			$	231,148			$	270,357
	Changes in Standardized Measure
	For the year ended December 31,
	2013				2012				2011
Standardized measure at the beginning of the period	$	231,148			$	270,357			$	198,916
Changes
Sales and transfers, net of production costs	(78,661		)		(84,044		)		(107,297		)
Net change in sales and transfer prices, net of production costs	(46,088		)		47,261				125,518
Net change due to purchases and sales of in place reserves	(145,711		)		(35,665		)		1,275
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	212,431				53,446				22,598
Changes in future development cost	153,983				39,815				(83,110		)
Revisions of quantity estimates	(68,958		)		(77,322		)		(949		)
Accretion of discount	25,010				30,989				68,384
Net change in income taxes	1,751				13,969				(32,918		)
Changes in production rates, timing and other	(959		)		(27,658		)		77,940
Aggregate change	52,798				(39,209		)		71,441
Standardized measure at the end of period	$	283,946			$	231,148			$	270,357

Other

Other	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Other	'
	Other
	Commitments and Contingencies: The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
	The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
	Global Settlement with Joint Interest Partner: During 2011, the Company and a joint interest partner entered into a settlement agreement related to various disputes. All matters were settled and as result of the settlement agreement the Company received an interest in other specialized deep water property and equipment. The Company recognized a gain of $5,041 as a result of the settlement and classified the property and equipment received as held for sale assets, included within other property and equipment since the Company had no use for this type of equipment in its operations. Since the settlement with its joint interest partner, the Company has sold a portion of these assets and has continued to actively market the remaining assets throughout 2012 and 2013. During 2012, after selling assets valued at $527 during the year, the Company determined that certain equipment components were not usable without additional rework and thus recorded an impairment charge to its Statement of Operations of $1,177 during 2012. During 2013, after selling assets value at $114 during the year, the Company has made a decision to abandon the equipment. As such the Company recorded an impairment charge of $1,707 to its Statement of Operations, representing the remaining value of this equipment.
	Operating Leases: In April 2012, the Company took delivery of a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed on March 6, 2014 for an additional two year term ending April 2016. On August 1, 2013, the Company contracted a second horizontal drilling rig (the “Patterson Rig”) for a one-year term, though the Company provided notice on February 17, 2014 that it will cancel its Patterson rig contract on or about March 17, 2014. Under the early termination provisions of the agreement, estimated termination payments for this rig will be approximately $2,055 in 2014. Should the lessor be able to re-charter the rig, the termination payments would be reduced. To replace the Patterson Rig, the Company contracted a replacement rig (the “Cactus 2 Rig”) for a term of two years, which is scheduled to commence operations on April 1, 2014. Similar to the Patterson Rig, the Cactus 1 and 2 Rig lease agreements also include early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee. Lease costs recorded during 2013 were $12,860. Lease payments as of December 31, 2013 will approximate $13,954, $9,308 and $2,295 in 2014, 2015 and 2016, respectively. Including the additional lease commitments executed subsequent to December 31, 2013, the Company’s drilling rig lease commitments as of March 10, 2014 are $19,732, $18,250 and $4,500 in 2014, 2015, and 2016, respectively.
	Property Acquisitions and Dispositions
	Acquisitions
	During the second quarter of 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,301 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 9).
	During the first quarter of 2012, the Company acquired approximately 16,233 gross (14,653 net) acres in Borden County, which is located in the northern Midland basin. The northern Midland basin has had limited drilling activity compared with the southern Midland basin (where our current production is located), increasing the economic risk related to these drilling activities. The purchase price of $14,538 was funded from existing cash balances. During the third quarter of 2012, we acquired an additional 8,095 gross acres (6.964 net) in this area for a total consideration of $4,835.
	During the second quarter of 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1.762 net) acres in southern Reagan County, Texas for a total purchase price of $12,012, which was financed with a draw on the Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.
	Dispositions
	During the fourth quarter of 2013, the Company closed on the sale of its 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties. The Company sold its interest in Medusa to W&T, an unrelated third-party, for a total net cash consideration of approximately $88,000 after customary purchase price adjustments. Also during the fourth quarter of 2013, the Company closed on the sale of its 69% interest in the Swan Lake field for $2,000. This was the Company’s only field in the Haynesville shale. Consistent with the Company’s accounting policy discussed in Note 2, the proceeds from these sales were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.
	Effective December 28, 2012, the Company closed on the sale of its 11.25% working interest in the Habanero field (Garden Banks Block 341). The Company sold its interest in Habanero to Shell Offshore Inc., a subsidiary of Royal Dutch Shell Plc, for an estimated net cash consideration of $39,410 after customary purchase price adjustments. As noted above, the proceeds from this sale were accounted for as a reduction to capitalized costs as the sale did not significantly alter the relationship between capitalized costs and proved reserves.

Summarized_Quarterly_Financial

Summarized Quarterly Financial Information (unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Summarized Quarterly Financial Information (unaudited)	'
	Summarized Quarterly Financial Information (Unaudited)
	2013	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	Total revenues	$	22,541		$	22,760	$	30,797		$	26,471
	Income from operations	898			957		6,345			2,464
	Net income (loss)	(800		)	758		1,082			3,264
	Income (loss) available to common shares	(800		)	78		(892		)	1,291
	Income (loss) per common share - basic	$	(0.02	)	$	0	$	(0.02	)	$	0.03
	Income (loss) per common share - diluted	$	(0.02	)	$	0	$	(0.02	)	$	0.03
	2012	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	Total revenues	$	29,294		$	25,360	$	27,402		$	28,677
	Income from operations	2,716			2,759		2,563			2,652
	Income (loss) available to common shares	488			3,799		(1,105		)	(435		)
	Income (loss) per common share - basic	$	0.01		$	0.1	$	(0.03	)	$	(0.01	)
	Income (loss) per common share - diluted	$	0.01		$	0.09	$	(0.03	)	$	(0.01	)

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Use of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of 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.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Receivable	'
	Accounts Receivable
	Accounts receivable consists primarily of accrued oil and natural gas production receivables.
Revenue Recognition and Natural Gas Balancing	'
	Revenue Recognition and Natural Gas Balancing
	The Company recognizes revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the lower of cost or market. The revenue we receive from the sale of NGLs is included in natural gas sales.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $14,753, $13,331 and $11,857 of these internal costs during 2013, 2012 and 2011, respectively.
	When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized in income.
	Costs of oil and natural gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.
	Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. See Note 12 for additional information regarding the Company’s oil and natural gas properties.
	Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data.  Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC’s rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.
Other Property and Equipment	'
	Other Property and Equipment
	The Company depreciates its other property and equipment of $7,255 and $6,424 at December 31, 2013 and 2012, respectively, using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $750, $760 and $645 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011, respectively. The accumulated depreciation on other property and equipment was $13,240 and $13,238 as of December 31, 2013 and 2012, respectively. As discussed in Note 13, during 2013, the Company recorded an impairment charge to reduce to zero the carrying values of its assets held for sale. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Capitalized Interest	'
	Capitalized Interest
	The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization (e.g. unevaluated properties). Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	The Company is required to record its estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses in the consolidated statements of operations.
Derivatives	'
	Derivatives
	The Company’s derivative contracts executed prior to 2012 were designated as cash flow hedges, and were recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. Ineffective derivative contracts or ineffective portions of contracts designated as cash flow hedges were recognized as derivative expense (income). The last of the Company’s derivative contracts designated as cash flow hedges expired on December 31, 2012. Derivative contracts executed during 2013 and outstanding as of December 31, 2013 were not designated as accounting hedges, and are carried on the balance sheet at their fair market value. Changes in the fair value of derivative contracts not designated as accounting hedges are reflected in earnings as a gain or loss on derivative contracts.
Income Taxes	'
	Income Taxes
	Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. A valuation allowance is provided for that portion, if any, of the asset for which it is deemed more likely than not that it will not be realized.
Share-based Compensation	'
	Share-Based Compensation
	The Company grants to directors and employees stock options, restricted stock awards (“RS awards”), and restricted stock unit awards (“RSU awards”) that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash-settleable RSU awards”).
	Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value as calculated using the Black-Scholes option pricing model and recognized straight-line over the vesting period (generally three years).
	RS awards, RSU awards and Cash-settleable RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash-settleable RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, with the estimated value recognized over the vesting period (generally three years).
Consolidation of Variable Interest Entities	'
	Consolidation of Variable Interest Entities
	In June 2009, the FASB issued an accounting standard which became effective for and was adopted by the Company on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, which resulted in Callon gaining the power to direct the activities of Callon Entrada, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company’s financial statements.
Earnings per Share (EPS)	'
	Earnings per Share (EPS)
	The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period.  Diluted EPS, using the treasury-stock method, reflects the potential dilution caused by the exercise of all options and vesting of all restricted stock and restricted stock units settleable in shares.
Recent Accounting Pronouncements	'
		Recent Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption.
	In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income and required disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, it requires that the Company present either on the face of its financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same reporting period. For amounts not reclassified in their entirety to net income, the Company is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Schedule of Revenue by Major Customers	'
	The following table identifies customers to whom it sold a greater than 10% of its total oil and natural gas production during each of the years ended:
		For the Year Ended December 31,
		2013		2012		2011
	Enterprise Crude Oil, LLC	38	%	32	%	16	%
	Shell Trading Company	31	%	39	%	45	%
	Plains Marketing, L.P.	15	%	15	%	17	%
	Other	16	%	14	%	22	%
	Total	100	%	100	%	100	%

Earnings_loss_per_Share_Tables

Earnings (loss) per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Computation of Earnings Per Share, Basic and Diluted	'
	A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):
		For the year ended December 31,
		2013			2012		2011
	Net income	$	4,304		$	2,747	$	106,396
	Preferred stock dividends	(4,627		)	—		—
	(a) Income (loss) available to common shareholders	$	(323	)	$	2,747	$	106,396
	(b) Weighted average shares outstanding	40,133			39,522		37,908
	Dilutive impact of stock options	—			8		18
	Dilutive impact of restricted stock	—			807		656
	(c) Weighted average shares outstanding
	for diluted net income (loss) per share (1)	40,133			40,337		38,582
	Basic Income (loss) per share (a/b)	$	(0.01	)	$	0.07	$	2.81
	Diluted Income (loss) per share (a/c)	$	(0.01	)	$	0.07	$	2.76
	The following were excluded from the diluted EPS calculations because their effect would be anti-dilutive:
	Stock options	52			52		67
	Restricted stock	398			123		816

Borrowings_Tables

Borrowings (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Borrowings	'
		For the year ended December 31,
		2013			2012
	Principal components:
	Credit Facility	$	22,000		$	10,000
	13% Senior Notes due 2016, principal	48,481			96,961
	Total principal outstanding	$	70,481		$	106,961
	Non-cash components:
	13% Senior Notes due 2016 unamortized deferred credit	5,267			13,707
	Total carrying value of borrowings	$	75,748		$	120,668
Schedule of Deferred Credit Balance Related to Senior Notes	'
	The following table summarizes the Company’s deferred credit balance at December 31, 2013:
	Gross Carrying		Accumulated Amortization at	Carrying Value at		Amortization Recorded during Current Year	Estimated Annual Amortization Expense Expected to be Recognized in
	Amount		December 31, 2013	December 31, 2013		(a)	2014
	$31,507		$26,240	$5,267		$8,440	$5,267
	(a)	Of the amount recorded as amortization during the current year, $3,165 was recorded as a reduction of interest expense and $5,275 (discussed below) was recorded as a component of the gain on early extinguishment of debt.

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	'
	The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
			Balance Sheet Presentation				Asset Fair Value								Liability Fair Value						Net Derivative Fair Value
	Commodity		Classification		Line Description		12/31/13				12/31/12				12/31/13			12/31/12			12/31/13			12/31/12
	Derivatives not designated as Hedging Instruments under ASC 815
	Natural gas		Current		Fair market value of derivatives		$	60			$	—			$	—		$	(125	)	$	60		$	(125	)
	Natural gas		Non-current		Other long-term liabilities		—				—				(72		)	(116		)	(72		)	(116		)
	Oil		Current		Fair market value of derivatives		—				1,674				(1,036		)	—			(1,036		)	1,674
	Oil		Non-current		Other long-term assets		—				250				—			—			—			250
			Totals				$	60			$	1,924			$	(1,108	)	$	(241	)	$	(1,048	)	$	1,683
	The following presents the impact of this presentation to the Company’s recognized assets and liabilities at December 31, 2013:
			Presented without								As Presented with
			Effects of Netting				Effects of Netting				Effects of Netting
	Current assets: Fair value of hedging contracts		$	8			$	52			$	60
	Long-term assets: Fair value of hedging contracts		—				—				—
	Current liabilities: Fair value of hedging contracts		1,088				(52		)		1,036
	Long-term liabilities: Fair value of hedging contracts		(72		)		—				(72		)
Schedule of Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance	'
	Derivatives not designated as hedging instruments under ASC 815
	For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges and are recorded in the Statement of Operations as gain or loss on derivative contracts:
		For the year ended December 31,
		2013				2012				2011
	Natural gas derivatives
	Net (loss) gain on derivatives, settled	$	(147	)		$	34			$	—
	Net gain (loss) on derivatives, net of settlements	229				(241		)		—
	Subtotal gain (loss), net	$	82			$	(207	)		$	—
	Oil derivatives
	Net gain, on derivatives, settled	$	1,518			$	—			$	—
	Net (loss) gain on derivatives, net of settlements	(2,960		)		1,924				—
	Subtotal (loss) gain, net	$	(1,442	)		$	1,924			$	—
	Total (loss) gain on derivative instruments included in Statement of Operations	$	(1,360	)		$	1,717			$	—
Schedule of Derivatives Designated as Hedging Instruments, Gain (Loss) in Statement of Financial Performance	'
	Derivatives designated as hedging instruments under ASC 815
	The table below presents the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and natural gas sales for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
		For the year ended December 31,
		2013				2012				2011
	Amount of gain (loss) reclassified from OCI into income (effective portion)	$	—			$	1,420			$	(375	)
	Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)	—				—				—
Schedule of Outstanding Oil and Natural Gas Derivative Contracts	'
	Listed in the table below are the outstanding oil and natural gas derivative contracts as of December 31, 2013:
	Commodity		Instrument		Average Notional Volumes per Month		Quantity Type		Put/Call Price				Fixed-Price Swap				Period	Designation under ASC 815
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Jan14 - Mar14	Not Designated
	Natural gas		Swap		60		MMBtu		n/a				$	4.36			Jan14 - Mar14	Not Designated
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Jan14 - Dec14	Not Designated		(a)
	Oil		Swap		30		Bbls		n/a				$	93.35			Jan14 - Dec14	Not Designated
	Oil		Put Option		30		Bbls		$	70			n/a				Jan14 - Dec14	Not Designated
	Oil		Swap		9		Bbls		n/a				$	94.58			Jan14 - Dec14	Not Designated
	Natural gas		Swap		46		MMBtu		n/a				$	4.25			Apr14 - Dec14	Not Designated
	Natural gas		Call Option		38		MMBtu		$	4.75			n/a				Apr14 - Dec14	Not Designated
	Natural gas		Call Option		37		MMBtu		$	5			n/a				Jan15 - Dec15	Not Designated
	(a)	The short natural gas call option, when combined with the Company’s long production position, represents a “covered call,” and creates a $4.75/MMbtu ceiling during the covered period.
	Subsequent Event Activity:
	Derivative contracts executed subsequent to December 31, 2013 include the following:
	Commodity		Instrument		Average Notional Volumes per Month		Quantity Type		Put/Call Price		Fixed-Price Swap				Period		Designation under ASC 815
	Oil		Swap		15		Bbls		n/a		$	94.15			Feb14 - Mar14		Not Designated
	Oil		Swap		15		Bbls		n/a		$	92.8			Apr14 - Jun14		Not Designated
	Oil		Swap		15		Bbls		n/a		$	90.4			Jul14 - Sep14		Not Designated
	Oil		Swap		15		Bbls		n/a		$	88.64			Oct14 - Dec14		Not Designated

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Summary of Fair Value of Financial Instruments at Carrying and Fair Value	'
	The following table summarizes the respective carrying and fair values at:
		For the year ended December 31,
		2013						2012
		Carrying Value			Fair Value			Carrying Value			Fair Value
	Credit Facility	$	22,000		$	22,000		$	10,000		$	10,000
	13% Senior Notes due 2016 (a)	53,748			50,299			110,668			100,112
	Total	$	75,748		$	72,299		$	120,668		$	110,112
	(a)	2013 and 2012 fair values are calculated only in relation to the $48,481 and $96,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $5,267 and $13,707, respectively represents the Company’s deferred credits and have been excluded from the fair value calculation. See Note 4 for additional information.
Fair Value Liabilities Measured on Recurring Basis	'
	The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
	December 31, 2013		Balance Sheet Presentation	Level 1			Level 2			Level 3			Total
	Assets
	Derivative financial instruments - current Portion		Fair market value of derivatives	$	—		$	60		$	—		$	60
	Derivative financial instruments - non-current		Other assets, net	—			—			—			—
	Sub-total assets			$	—		$	60		$	—		$	60
	Liabilities
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	1,036		$	—		$	1,036
	Derivative financial instruments - non-current		Other long-term liabilities	—			72			—			72
	Sub-total liabilities			$	—		$	1,108		$	—		$	1,108
	Total			$	—		$	(1,048	)	$	—		$	(1,048	)
	December 31, 2012		Balance Sheet Presentation	Level 1			Level 2			Level 3			Total
	Assets
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	1,674		$	—		$	1,674
	Derivative financial instruments - non-current		Other assets, net	—			250			—			250
	Sub-total assets			$	—		$	1,924		$	—		$	1,924
	Liabilities
	Derivative financial instruments - current portion		Fair market value of derivatives	$	—		$	125		$	—		$	125
	Derivative financial instruments - non-current		Other long-term liabilities	—			116			—			116
	Sub-total liabilities			$	—		$	241		$	—		$	241
	Total			$	—		$1,683			$	—		$1,683

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Cash-Settleable Vesting Period RSU Awards	'
	As of December 31, 2013, the Company had the following cash-settleable RSU awards outstanding (including those that are not based on a market condition):
		Base Units	Potential Minimum	Potential Maximum
		Outstanding at	Units at Vesting at	Units at Vesting at
	Vesting in 2014	510	45	975
	Vesting in 2015	909	60	1,758
	Vesting in 2016	66	66	66
	Other	92	92	92
	Total cash-settleable RSU awards	1,577	263	2,891

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan	'
		For the year ended December 31,
		2013								2012					2011
	Share-based compensation expense for:	Equity-based				Liability-based				Equity-based			Liability-based		Equity-based		Liability-based
	Options	$	—			$	—			$	—		$	—	$	24	$	—
	RSU equity awards	3,975				—				4,210			—		2,832		—
	Cash-settleable RSU awards	—				5,347				—			2,916		—		1,335
	401(k) contributions in shares	219				—				218			—		202		—
	Total share-based compensation expense (a)	$	4,194			$	5,347			$	4,428		$	2,916	$	3,058	$	1,335
	(a)	The portion of this share-based compensation expense that was included in general and administrative expense totaled $5,751, $4,081 and $2,502 for the same years respectively, and the portion capitalized to oil and gas properties was $3,791, $3,263 and $1,891, respectively.
Schedule of Unrecognized Compensation Cost, Nonvested Awards	'
	The following table presents the specified share-based compensation expense for the indicated periods:
		For the year ended December 31,
	Unrecognized compensation costs related to:	2013			2012			2011
	Unvested RSU equity awards	5,331			6,320			5,748
	Unvested cash-settleable RSU awards	7,669			2,826			2,498
	The Company’s future expected share-based compensation cost related to unvested RSU and cash-settleable RSU awards is expected to be recognized over a weighted-average period of 1.4 years.
Schedule of Cash-Settleable RSU awards	'
	The following table summarizes the Company’s cash-settleable RSU awards for the periods indicated:
	Consolidated Balance Sheets Classification		2013				2012				2011
	Accounts payable and accrued liabilities - current portion		$	4,173			$	1,429			$	604
	Other long-term liabilities - non-current portion		3,409				1,017				2,309
	Total cash-settleable RSU awards		$	7,582			$	2,446			$	2,913
Schedule of Share-based Compensation, Restricted Stock Units Award Activity	'
	The following table represents unvested restricted stock activity for the year ended December 31, 2013:
		Weighted average
		Number of Shares			Grant-Date Fair Value per Share				Period over which expense is expected to be recognized
	Outstanding at the beginning of the period	2,295			$	5.58
	Granted	944			3.82
	Vested (a)	(754	)		5.1
	Forfeited	(223	)		5.37
	Outstanding at the end of the period	2,262			$	5.03			1.5
	a.	The fair value of shares vested was $2,689.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Deferred Tax Assets and Liabilities	'
	The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations:
		For the Year Ended December 31
		2013				2012
	Deferred tax asset
	Federal net operating loss carryforward	$	70,365			$	87,774
	Statutory depletion carryforward	8,880				8,184
	Alternative minimum tax credit carryforward	208				208
	Asset retirement obligations	1,024				3,357
	Other	7,575				9,571
	Total deferred tax asset	88,052				109,094
	Deferred tax liability
	Oil and natural gas properties	26,412				41,336
	Other	32				3,375
	Total deferred tax liability	26,444				44,711
	Net deferred tax asset	$	61,608			$	64,383
Summary of Operating Loss Carryforwards	'
	If not utilized, the Company’s federal operating loss (“NOL”) carryforwards will expire as follows:
							Year Expiring
			Total				2014-2019			2020-2022			2023-2025		2026-2028		2029-2033
	Federal NOL carryforwards		$	201,042			$	—		$	48,986		$	65,878	$	32,714	$	53,464
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations.
			For the Years Ended December 31,
	Component of Income Tax Rate Reconciliation		2013				2012			2011
	Income tax expense computed at the statutory federal income tax rate		35		%		35		%	35		%
	Change in valuation allowance		—		%		—		%	(227		)%
	Percentage depletion carryforward		(8		)%		(22		)%	(3		)%
	State taxes net of federal benefit		4		%		6		%	—		%
	Restricted stock and stock options		5		%		2		%	—		%
	Section 162(m)		6		%		22		%	—		%
	Other		—		%		4		%	4		%
	Effective income tax rate		42		%		47		%	(191		)%
			For the Years Ended December 31,
	Components of Income Tax Expense		2013				2012			2011
	Current federal income tax benefit		$	—			$	—		$	—
	Current state income tax expense		326				110			—
	Deferred federal income tax expense		2,652				1,777			13,176
	Deferred state income tax expense		126				336			—
	Valuation allowance		—				—			(82,459		)
	Total income tax expense (benefit)		$	3,104			$	2,223		$	(69,283	)

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Schedule of Change in Asset Retirement Obligation	'
	The following table summarizes the activity for the Company’s asset retirement obligations:
		For the Year Ended December 31,
		2013			2012
	Asset retirement obligations at beginning of the period	$	13,301		$	13,938
	Accretion expense	1,785			2,253
	Liabilities incurred	679			205
	Liabilities settled	(457		)	(1,073		)
	Liabilities related to oil and gas properties sold	(4,765		)	(877		)
	Revisions to estimate	(3,811		)	(1,145		)
	Asset retirement obligations at end of period	6,732			13,301
	Less: current asset retirement obligations	(4,120		)	(2,336		)
	Long-term asset retirement obligations at the end of the period	$	2,612		$	10,965

Supplemental_Oil_and_Natural_G1

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	'
	Changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows:
		Reserve Quantities
		For the year ended December 31,
		2013			2012			2011
	Proved developed and undeveloped reserves:
	Oil (MBbls):
	Beginning of period	10,780			10,075			8,149
	Revisions to previous estimates	(2,540	)		(488	)		(110	)
	Purchase of reserves in place	150			38			—
	Sale of reserves in place	(3,294	)		(504	)		(30	)
	Extensions and discoveries	7,713			2,636			3,062
	Production	(911	)		(977	)		(996	)
	End of period	11,898			10,780			10,075
	Natural Gas (MMcf):
	Beginning of period	19,753			35,118			32,957
	Revisions to previous estimates	(5,351	)		(10,838	)		486
	Purchase of reserves in place	317			115			—
	Sale of reserves in place	(4,576	)		(4,404	)		(308	)
	Extensions and discoveries	10,619			3,350			7,064
	Production	(3,011	)		(3,588	)		(5,081	)
	End of period	17,751			19,753			35,118
	Proved developed reserves:
	Oil (MBbls):
	Beginning of period	4,955			5,069			4,503
	End of period	5,960			4,955			5,069
	Natural Gas (MMcf):
	Beginning of period	10,680			11,605			12,715
	End of period	9,059			10,680			11,605
	MBOE:
	Beginning of period	6,735			7,003			6,622
	End of period	7,470			6,735			7,003
	Proved undeveloped reserves:
	Oil (MBbls):
	Beginning of period	5,825			5,006			3,645
	End of period	5,938			5,825			5,006
	Natural Gas (MMcf):
	Beginning of period	9,073			23,513			20,241
	End of period	8,692			9,073			23,513
	MBOE
	Beginning of period	7,337			8,925			7,019
	End of period	7,387			7,337			8,925
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	'
	The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
			2013				2012				2011
	Average 12-month price, net of differentials, per Mcf of natural gas		$	5.45			$	4.81			$	5.6
	Average 12-month price, net of differentials, per barrel of oil		$	92.16			94.68				98.98
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	'
	The oil prices of $92.16 and $94.68 used in the 2013 and 2012 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
		Standardized Measure
		For the year ended December 31,
		2013				2012				2011
	Future cash inflows	$	1,193,299			$	1,115,570			$	1,194,079
	Future costs -
	Production	(357,005		)		(249,329		)		(356,653		)
	Development and net abandonment	(155,667		)		(273,817		)		(268,628		)
	Future net inflows before income taxes	680,627				592,424				568,798
	Future income taxes	(68,239		)		(55,772		)		(78,813		)
	Future net cash flows	612,388				536,652				489,985
	10% discount factor	(328,442		)		(305,504		)		(219,628		)
	Standardized measure of discounted future net cash flows	$	283,946			$	231,148			$	270,357
		Changes in Standardized Measure
		For the year ended December 31,
		2013				2012				2011
	Standardized measure at the beginning of the period	$	231,148			$	270,357			$	198,916
	Changes
	Sales and transfers, net of production costs	(78,661		)		(84,044		)		(107,297		)
	Net change in sales and transfer prices, net of production costs	(46,088		)		47,261				125,518
	Net change due to purchases and sales of in place reserves	(145,711		)		(35,665		)		1,275
	Extensions, discoveries, and improved recovery, net of future production and development costs incurred	212,431				53,446				22,598
	Changes in future development cost	153,983				39,815				(83,110		)
	Revisions of quantity estimates	(68,958		)		(77,322		)		(949		)
	Accretion of discount	25,010				30,989				68,384
	Net change in income taxes	1,751				13,969				(32,918		)
	Changes in production rates, timing and other	(959		)		(27,658		)		77,940
	Aggregate change	52,798				(39,209		)		71,441
	Standardized measure at the end of period	$	283,946			$	231,148			$	270,357

Summarized_Quarterly_Financial1

Summarized Quarterly Financial Information (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information	'
	2013	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	Total revenues	$	22,541		$	22,760	$	30,797		$	26,471
	Income from operations	898			957		6,345			2,464
	Net income (loss)	(800		)	758		1,082			3,264
	Income (loss) available to common shares	(800		)	78		(892		)	1,291
	Income (loss) per common share - basic	$	(0.02	)	$	0	$	(0.02	)	$	0.03
	Income (loss) per common share - diluted	$	(0.02	)	$	0	$	(0.02	)	$	0.03
	2012	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
	Total revenues	$	29,294		$	25,360	$	27,402		$	28,677
	Income from operations	2,716			2,759		2,563			2,652
	Income (loss) available to common shares	488			3,799		(1,105		)	(435		)
	Income (loss) per common share - basic	$	0.01		$	0.1	$	(0.03	)	$	(0.01	)
	Income (loss) per common share - diluted	$	0.01		$	0.09	$	(0.03	)	$	(0.01	)

Description_of_Business_and_Ba1

Description of Business and Basis of Presentation (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Production taxes	$4,133	$3,224	$2,062
Restatement Adjustment [Member]	'	'	'
Production taxes	'	$3,224	$2,062

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)

12 Months Ended

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

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Minimum [Member]

Maximum [Member]

General and Administrative Expense [Member]

General and Administrative Expense [Member]

General and Administrative Expense [Member]

Natural Gas [Member]

Natural Gas [Member]

Other Property and Equipment [Member]

Other Property and Equipment [Member]

Other Property and Equipment [Member]

Other Property and Equipment [Member]

Other Property and Equipment [Member]

Undivided Interest [Member]

Callon Entrada [Member]

Medusa Field [Member]

Medusa Spar, LLC [Member]

General and Administrative Expense [Member]

General and Administrative Expense [Member]

General and Administrative Expense [Member]

Medusa Spar, LLC [Member]

Accounting Policies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for doubtful accounts receivable, current

$73

$34

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Provision for doubtful accounts

'

'

'

'

'

45

0

-281

'

'

'

'

'

'

'

'

'

'

'

Gas balancing receivables

'

'

'

'

'

'

'

'

71

93

'

'

'

'

'

'

'

'

'

Gas balancing payable

'

'

'

'

'

'

'

'

126

653

'

'

'

'

'

'

'

'

'

Capitalized costs, oil and gas producing activities, net

14,753

13,331

11,857

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Property, Plant and Equipment, Other, Net

7,255

10,058

'

'

'

'

'

'

'

'

7,255

6,424

'

'

'

'

'

'

'

Useful life

'

'

'

'3 years

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation

'

'

'

'

'

'

'

'

'

'

'

'

750

760

645

'

'

'

'

Accumulated depreciation

'

'

'

'

'

'

'

'

'

'

13,240

13,238

'

'

'

'

'

'

'

Assets Held-for-sale, at Carrying Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

Capitalized Costs, Unproved Properties, Capitalized Interest

4,410

2,109

573

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest paid

$13,189

$13,920

$14,922

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Divestiture of Business, Percentage Of Business Sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

10.00%

Ownership Percentage of Production Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Major Customers) (Details) (Sales Revenue, Goods, Net [Member], Customer Concentration Risk [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Concentration Risk [Line Items]	'	'	'
Concentration Risk, Percentage	100.00%	100.00%	100.00%
Enterprise Crude Oil, LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration Risk, Percentage	38.00%	32.00%	16.00%
Shell Trading Company [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration Risk, Percentage	31.00%	39.00%	45.00%
Plains Marketing, L.P. [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration Risk, Percentage	15.00%	15.00%	17.00%
Other [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration Risk, Percentage	16.00%	14.00%	22.00%

Earnings_loss_per_Share_Detail

Earnings (loss) per Share (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

Earnings Per Share, Basic and Diluted

'

'

'

'

'

'

'

'

'

'

'

Net income

$3,264

$1,082

$758

($800)

'

'

'

'

$4,304

$2,747

$106,396

Preferred stock dividends

'

'

'

'

'

'

'

'

-4,627

0

0

Income (loss) available to common shareholders

$1,291

($892)

$78

($800)

($435)

($1,105)

$3,799

$488

($323)

$2,747

$106,396

Weighted average shares outstanding

'

'

'

'

'

'

'

'

40,133

39,522

37,908

Weighted average shares outstanding for diluted net income (loss) per share

'

'

'

'

'

'

'

'

40,133

[1]

40,337

[1]

38,582

[1]

Income (loss) per common share - basic

$0.03

($0.02)

$0

($0.02)

($0.01)

($0.03)

$0.10

$0.01

($0.01)

$0.07

$2.81

Income (loss) per common share - diluted

$0.03

($0.02)

$0

($0.02)

($0.01)

($0.03)

$0.09

$0.01

($0.01)

$0.07

$2.76

Options [Member]

'

'

'

'

'

'

'

'

'

'

'

Earnings Per Share, Basic and Diluted

'

'

'

'

'

'

'

'

'

'

'

Weighted average shares outstanding, adjustment

'

'

'

'

'

'

'

'

0

8

18

Excluded from the diluted EPS calculation because their effect would be anti-dilutive

'

'

'

'

'

'

'

'

52

52

67

Restricted Stock [Member]

'

'

'

'

'

'

'

'

'

'

'

Earnings Per Share, Basic and Diluted

'

'

'

'

'

'

'

'

'

'

'

Weighted average shares outstanding, adjustment

'

'

'

'

'

'

'

'

0

807

656

Excluded from the diluted EPS calculation because their effect would be anti-dilutive

'

'

'

'

'

'

'

'

398

123

816

[1]

Because the Company reported a loss for the year ended December 31, 2013, no unvested stock awards were included in computing loss per share because the effect was anti-dilutive.

Borrowings_Schedule_of_Borrowi

Borrowings (Schedule of Borrowings) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Principal components:	'	'
Credit Facility	$22,000	$10,000
13% Senior Notes due 2016	48,481	96,961
Long-term debt, gross	70,481	106,961
Non-cash components:	'	'
Deferred Credit	5,267	13,707
Long-term Debt	75,748	120,668
Revolving Credit Facility [Member]	'	'
Principal components:	'	'
Credit Facility	22,000	10,000
Senior Notes [Member] | 13% Senior Notes due 2016 [Member]	'	'
Principal components:	'	'
13% Senior Notes due 2016	48,481	'
Non-cash components:	'	'
Deferred Credit	$5,267	$13,707

Borrowings_Senior_Secured_Revo

Borrowings (Senior Secured Revolving Credit Facility) (Details) (Revolving Credit Facility [Member], USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Mar. 10, 2014	Mar. 10, 2014	Mar. 10, 2014
	Regions Bank [Member]	Regions Bank [Member]	Regions Bank [Member]	JPMorgan Chase Bank [Member]	JPMorgan Chase Bank [Member]	JPMorgan Chase Bank [Member]
		Minimum [Member]	Maximum [Member]	Subsequent Event [Member]	Minimum [Member]	Maximum [Member]
					Subsequent Event [Member]	Subsequent Event [Member]
Line of Credit Facility [Line Items]	'	'	'	'	'	'
Maximum borrowing capacity	$200,000,000	'	'	$500,000,000	'	'
Current borrowing capacity	83,000,000	'	'	95,000,000	'	'
Credit Facility	$22,000,000	'	'	'	'	'
Interest rate at period end (as a percent)	2.92%	'	'	'	'	'
Basis Spread on LIBOR (as a percent)	'	2.50%	3.00%	'	1.75%	2.75%
Unused capacity, commitment fee (as a percent)	0.50%	'	'	0.50%	'	'

Borrowings_Second_Lien_Term_Lo

Borrowings (Second Lien Term Loan Facility) (Details) (JPMorgan Chase Bank, Second Lien [Member], Line of Credit [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Line of Credit Facility [Line Items]	'
Current borrowing capacity	$125,000
Line of Credit Facility, Initial Commitment	100,000
Line of Credit Facility, Additional Borrowing Capacity	$25,000
Basis Spread on LIBOR (as a percent)	7.75%
Unused capacity, commitment fee (as a percent)	0.50%
Line of Credit Facility, Discount Percentage	1.00%
Prior to First Anniversary [Member]	'
Line of Credit Facility [Line Items]	'
Line of Credit Facility, Prepayment Premium Percentage	102.00%
After First Anniversary but Prior to Second Anniversary [Member]	'
Line of Credit Facility [Line Items]	'
Line of Credit Facility, Prepayment Premium Percentage	101.00%

Borrowings_13_Senior_Notes_due

Borrowings (13% Senior Notes due 2016 (bSenior Notesb) and Deferred Credit) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jun. 30, 2012

Mar. 31, 2011

Feb. 28, 2011

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Nov. 30, 2009

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

13% Senior Notes due 2016

$48,481

$96,961

'

$48,481

'

'

'

$48,481

'

'

'

'

Debt instrument, interest rate, stated (as a percent)

'

'

'

13.00%

'

'

'

13.00%

13.00%

13.00%

13.00%

'

Subsidiary guarantor owned (as a percent)

'

'

'

100.00%

'

'

'

100.00%

'

'

'

'

Debt Instrument, Reduction of Note Carrying Amount by Fair Value of Common and Preferred Stock Issued

'

'

'

'

'

'

'

'

'

'

'

11,527

Gross Carrying Amount

'

'

'

31,507

'

'

'

31,507

'

'

'

31,507

Debt instrument, interest rate, effective (as a percent)

'

'

'

8.50%

'

'

'

8.50%

'

'

'

'

Accumulated Amortization

20,814

17,800

'

26,240

'

'

'

26,240

'

'

'

'

Carrying Value

5,267

13,707

'

5,267

'

'

'

5,267

13,707

'

'

'

Amortization Recorded during Current Year

'

'

'

'

'

'

'

8,440

[1]

'

'

'

'

Amortization of Deferred Credit Expected to be Recorded during 2014

'

'

'

'

'

'

'

5,267

'

'

'

'

Amortization of deferred credit as reduction of interest expense

'

'

'

'

'

'

'

3,165

'

'

'

'

Accelerated Amortization of Deferred Credit

'

'

'

5,275

'

6,004

'

5,275

1,591

'

'

'

Gain on extinguishment of debt

3,696

1,366

1,942

3,696

1,366

1,974

'

'

'

'

'

'

Repayment of Senior Notes Including Redemption Expenses

50,060

10,225

35,062

50,057

10,225

35,062

'

'

'

'

'

'

Debt Instrument, Redemption Expenses

'

'

'

1,576

225

4,062

'

'

'

'

'

'

Debt Instrument, Carrying Value Including Accelerated Amortization of Deferred Credit

'

'

'

53,756

'

37,004

'

53,756

11,591

'

'

'

Repayments of senior debt

'

'

'

'

$10,000

'

$31,000

'

'

'

'

'

[1]

Of the amount recorded as amortization during the current year, $3,165 was recorded as a reduction of interest expense and $5,275 (discussed below) was recorded as a component of the gain on early extinguishment of debt.

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities (Derivatives Fair Value By Balance Sheet Location) (Details) (Not Designated as Hedging Instrument [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$60	$1,924
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-1,108	-241
Derivative, Fair Value, Net	-1,048	1,683
Current liabilities - Fair market value of derivatives [Member]	'	'
Derivative [Line Items]	'	'
Derivative Assets (Liability), Fair Value, Gross Asset Net	60	'
Derivative Assets (Liability), Fair Value, Gross Liability Net	1,036	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	8	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1,088	'
Current liabilities - Fair market value of derivatives [Member] | Natural gas [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	60	'
Derivative Asset, Fair Value, Gross Liability	'	0
Derivative Liability, Fair Value, Gross Asset	0	'
Derivative Liability, Fair Value, Gross Liability	'	-125
Derivative Assets (Liability), Fair Value, Gross Asset Net	60	'
Derivative Assets (Liability), Fair Value, Gross Liability Net	'	-125
Non-current liabilities - Other long-term liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative Assets (Liability), Fair Value, Gross Liability Net	-72	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-72	'
Non-current liabilities - Other long-term liabilities [Member] | Natural gas [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Liability, Fair Value, Gross Liability	-72	-116
Derivative Assets (Liability), Fair Value, Gross Liability Net	-72	-116
Current assets - Fair market value of derivatives [Member] | Crude oil [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	'	1,674
Derivative Asset, Fair Value, Gross Liability	0	'
Derivative Liability, Fair Value, Gross Asset	'	0
Derivative Liability, Fair Value, Gross Liability	-1,036	'
Derivative Assets (Liability), Fair Value, Gross Asset Net	'	1,674
Derivative Assets (Liability), Fair Value, Gross Liability Net	-1,036	'
Non-current assets - Other long-term assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative Assets (Liability), Fair Value, Gross Asset Net	0	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	'
Non-current assets - Other long-term assets [Member] | Crude oil [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	250
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Assets (Liability), Fair Value, Gross Asset Net	$0	$250

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities (Derivative Netting Adjustments) (Details) (Not Designated as Hedging Instrument [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$60	$1,924
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-1,108	-241
Current liabilities - Fair market value of derivatives [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	8	'
Derivative Asset, Fair Value, Netting Adjustments	52	'
Derivative Assets (Liability), Fair Value, Gross Asset Net	60	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1,088	'
Derivative Liability, Fair Value, Netting Adjustments	-52	'
Derivative Assets (Liability), Fair Value, Gross Liability Net	1,036	'
Non-current assets - Other long-term assets [Member]	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	'
Derivative Asset, Fair Value, Netting Adjustments	0	'
Derivative Assets (Liability), Fair Value, Gross Asset Net	0	'
Non-current liabilities - Other long-term liabilities [Member]	'	'
Derivative [Line Items]	'	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-72	'
Derivative Liability, Fair Value, Netting Adjustments	0	'
Derivative Assets (Liability), Fair Value, Gross Liability Net	($72)	'

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities (Derivatives Designated as Hedging Instruments/ Derivatives Not Designated as Hedging Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Net gain (loss) on derivatives, net of settlements	($2,730)	$1,683	$0
Total (loss) gain on derivative instruments included in Statement of Operations	-1,360	1,717	0
Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Amount of Gain (Loss) Reclassified from OCI into Income	0	1,420	-375
Amount of Gain Recognized in Income	0	0	0
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Total (loss) gain on derivative instruments included in Statement of Operations	-1,360	1,717	0
Commodity Contract [Member] | Natural gas [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Net (loss) gain on derivatives, settled	-147	34	0
Net gain (loss) on derivatives, net of settlements	229	-241	0
Total (loss) gain on derivative instruments included in Statement of Operations	82	-207	0
Commodity Contract [Member] | Crude Oil [Member] | Not Designated as Hedging Instrument [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Net (loss) gain on derivatives, settled	1,518	0	0
Net gain (loss) on derivatives, net of settlements	-2,960	1,924	0
Total (loss) gain on derivative instruments included in Statement of Operations	($1,442)	$1,924	$0

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activities (Derivative Positions and Subsequent Event) (Details) (Commodity Contract [Member])

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Mar. 12, 2014

Natural gas [Member]

Derivative Collar [Member]

Average Ceiling Price per Instrument of $4.75 [Member]

Fixed-Price Swap per Instrument of $4.36 [Member]

Average Ceiling Price per Instrument of $4.75 A [Member]

Fixed-Price Swap per Instrument of $93.35 [Member]

Average Floor Price per Instrument of $70.00 [Member]

Average Floor Price per Instrument of $70.00 [Member]

Fixed-Price Swap per Instrument of $94.58 [Member]

Fixed-Price Swap per Instrument of $4.25 [Member]

Average Ceiling Price per Instrument of $5.00 [Member]

Fixed-Price Swap per Instrument of $94.15 [Member]

Fixed-Price Swap per Instrument of $94.15 [Member]

Fixed-Price Swap per Instrument of $92.80 [Member]

Fixed-Price Swap per Instrument of $92.80 [Member]

Fixed-Price Swap per Instrument of $90.40 [Member]

Fixed-Price Swap per Instrument of $90.40 [Member]

Fixed-Price Swap per Instrument of $88.64 [Member]

Fixed-Price Swap per Instrument of $88.64 [Member]

Average Ceiling Price per Instrument of $4.75 [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Subsequent Event [Member]

Not Designated as Hedging Instrument [Member]

Subsequent Event [Member]

Not Designated as Hedging Instrument [Member]

Subsequent Event [Member]

Not Designated as Hedging Instrument [Member]

Subsequent Event [Member]

Not Designated as Hedging Instrument [Member]

Crude Oil [Member]

Natural gas [Member]

Natural gas [Member]

Natural gas [Member]

Crude Oil [Member]

Crude Oil [Member]

Crude Oil [Member]

Crude Oil [Member]

Natural gas [Member]

Natural gas [Member]

Crude Oil [Member]

Subsequent Event [Member]

Crude Oil [Member]

Subsequent Event [Member]

Crude Oil [Member]

Subsequent Event [Member]

Crude Oil [Member]

Subsequent Event [Member]

Swap [Member]

Call Option [Member]

Swap [Member]

Call Option [Member]

Swap [Member]

Put Option [Member]

Put Option [Member]

Swap [Member]

Swap [Member]

Call Option [Member]

Swap [Member]

Crude Oil [Member]

Swap [Member]

Crude Oil [Member]

Swap [Member]

Crude Oil [Member]

Swap [Member]

Crude Oil [Member]

Swap [Member]

Swap [Member]

Swap [Member]

Swap [Member]

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Nonmonetary Notional Amount (in Volumes per Month)

'

40,000

38,000

60,000

38,000

30,000

30,000

30,000

9,000

46,000

37,000

'

15,000

'

15,000

'

15,000

'

15,000

Derivative, Average Cap Price

'

'

'

4.36

'

93.35

'

'

94.58

4.25

'

94.15

'

92.8

'

90.4

'

88.64

'

Average Ceiling Price per Hedge (in dollars per instrument)

4.75

'

4.75

'

4.75

'

70

'

'

'

5

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value) (Details) (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]	'		'
Credit Facility	$22,000		$10,000
13% Senior Notes due 2016	48,481		96,961
Deferred Credit	5,267		13,707
Derivative Assets	'		'
Derivative Assets, Current	60		1,674
Liabilities	'		'
Derivative Liabilities, Current	1,036		125
Fair Value on a recurring basis [Member] | Level 1 [Member]	'		'
Derivative Assets	'		'
Derivative Assets	0		0
Liabilities	'		'
Derivative Liabilities	0		0
Fair Value, Net Asset (Liability)	0		0
Fair Value on a recurring basis [Member] | Level 2 [Member]	'		'
Derivative Assets	'		'
Derivative Assets	60		1,924
Liabilities	'		'
Derivative Liabilities	1,108		241
Fair Value, Net Asset (Liability)	-1,048		1,683
Fair Value on a recurring basis [Member] | Level 3 [Member]	'		'
Derivative Assets	'		'
Derivative Assets	0		0
Liabilities	'		'
Derivative Liabilities	0		0
Fair Value, Net Asset (Liability)	0		0
Fair Value on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'		'
Derivative Assets	'		'
Derivative Assets	60		1,924
Liabilities	'		'
Derivative Liabilities	1,108		241
Fair Value, Net Asset (Liability)	-1,048		1,683
Current assets - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 1 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Current	0		0
Current assets - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 2 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Current	60		1,674
Current assets - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 3 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Current	0		0
Current assets - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Current	60		1,674
Noncurrent assets - Other assets, net [Member] | Fair Value on a recurring basis [Member] | Level 1 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Noncurrent	0		0
Noncurrent assets - Other assets, net [Member] | Fair Value on a recurring basis [Member] | Level 2 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Noncurrent	0		250
Noncurrent assets - Other assets, net [Member] | Fair Value on a recurring basis [Member] | Level 3 [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Noncurrent	0		0
Noncurrent assets - Other assets, net [Member] | Fair Value on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'		'
Derivative Assets	'		'
Derivative Assets, Noncurrent	'		250
Current liabilities - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 1 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Current	0		0
Current liabilities - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 2 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Current	1,036		125
Current liabilities - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Level 3 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Current	0		0
Current liabilities - Fair market value of derivatives [Member] | Fair Value on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Current	1,036		125
Other long-term liabilities [Member] | Fair Value on a recurring basis [Member] | Level 1 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Noncurrent	0		0
Other long-term liabilities [Member] | Fair Value on a recurring basis [Member] | Level 2 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Noncurrent	72		116
Other long-term liabilities [Member] | Fair Value on a recurring basis [Member] | Level 3 [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Noncurrent	0		0
Other long-term liabilities [Member] | Fair Value on a recurring basis [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]	'		'
Liabilities	'		'
Derivative Liabilities, Noncurrent	72		116
Revolving Credit Facility [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Credit Facility	22,000		10,000
Fair Value [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Liabilities, Fair Value Disclosure	72,299		110,112
Fair Value [Member] | Revolving Credit Facility [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Lines of Credit, Fair Value Disclosure	22,000		10,000
Carrying Value [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Liabilities, Fair Value Disclosure	75,748		120,668
Carrying Value [Member] | Revolving Credit Facility [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Credit Facility	22,000		10,000
13% Senior Notes due 2016 [Member] | Senior Notes [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
13% Senior Notes due 2016	48,481		'
Deferred Credit	5,267		13,707
13% Senior Notes due 2016 [Member] | Portion at Fair Value, Fair Value Disclosure [Member] | Senior Notes [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
13% Senior Notes due 2016	48,481		96,961
13% Senior Notes due 2016 [Member] | Fair Value [Member] | Senior Notes [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
13% Senior Notes due 2016	50,299	[1]	100,112	[1]
13% Senior Notes due 2016 [Member] | Carrying Value [Member] | Senior Notes [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
13% Senior Notes due 2016	$53,748		$110,668
[1]	2013 and 2012 fair values are calculated only in relation to the $48,481 and $96,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $5,267 and $13,707, respectively represents the Companybs deferred credits and have been excluded from the fair value calculation.B See Note 4 for additional information.

Fair_Value_Measurements_Fair_V1

Fair Value Measurements Fair Value Measurements (Fair Value of Liabilities Measured on Nonrecurring Basis) (Details) (USD $)	12 Months Ended			3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2013
				Southern Portion of Midland Basin [Member]	Reagan and Upton Counties Acreage Purchase [Member]	Reagan and Upton Counties Acreage Purchase, Unevaluated [Member]	Reagan and Upton Counties Acreage Purchase, Evaluated [Member]
				bbl
				Oil_well
				acre
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'	'	'	'
Loss on Sale of Assets and Asset Impairment Charges	$1,707	$1,177	$0	'	'	'	'
Gas and Oil Area, Developed, Gross	'	'	'	2,468	'	'	'
Gas and Oil Area, Developed, Net	'	'	'	2,186	'	'	'
Business Combination, Consideration Transferred	'	'	'	11,000	'	'	'
Productive Oil Wells, Number of Wells, Gross	'	'	'	7	'	'	'
Proved Developed Reserves (Volume)	'	'	'	1,301,000	'	'	'
Business Combination, Consideration Transferred	'	'	'	'	$11,000	$2,000	$9,000

Employee_Benefit_Plans_Details

Employee Benefit Plans (Details) (USD $)	12 Months Ended					1 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013		31-May-11	Dec. 31, 2013	12-May-11
				RSUs [Member]		2011 Plan [Member]	2011 Plan [Member]	2011 Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'		'	'	'
Defined Contribution Plan, Employer Discretionary Contribution Amount	$923	$918	$811	'		'	'	'
Number of Shares Authorized	'	'	'	'		3,141	'	2,300
Number of Additional Shares Transferred	'	'	'	'		841	'	'
Number of Shares Available for grant	'	'	'	'		'	1,192	'
Expiration Period	'	'	'	'		'	'10 years	'
Granted	'	'	'	944		'	'	'
Forfeited in Period	'	'	'	223		'	'	'
Vested in Period	'	'	'	754	[1]	'	'	'
Non-cash expense related to equity share-based awards	$2,092	$1,697	$1,337	'		'	'	'
[1]	The fair value of shares vested was $2,689.

Employee_Benefit_Plans_CashSet

Employee Benefit Plans (Cash-Settleable RSU Awards) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Payments to settle vested liability share-based awards	$239	$3,383	$0
Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	1,577	'	'
Market-based Cash-settleable RSU Awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Number of Units Vesting Range, of Base Units Awarded	100.00%	150.00%	'
Cash-Settleable Awards, Base Units, Actual Units Vested During Period	260	364	'
Payments to settle vested liability share-based awards	1,669	2,626	'
Non-Market Based Cash-settleable RSU Awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Actual Units Vested During Period	65	143	'
Payments to settle vested liability share-based awards	$239	$763	'
Potential Minimum Units at Vesting [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Number of Units Vesting Range, of Base Units Awarded	0.00%	'	'
Potential Minimum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	263	'	'
Potential Maximum Units at Vesting [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Number of Units Vesting Range, of Base Units Awarded	200.00%	'	'
Potential Maximum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	2,891	'	'
Vesting in 2014 [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	510	'	'
Vesting in 2014 [Member] | Potential Minimum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	45	'	'
Vesting in 2014 [Member] | Potential Maximum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	975	'	'
Vesting in 2015 [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	909	'	'
Vesting in 2015 [Member] | Potential Minimum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	60	'	'
Vesting in 2015 [Member] | Potential Maximum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	1,758	'	'
Vesting in 2016 [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	66	'	'
Vesting in 2016 [Member] | Potential Minimum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	66	'	'
Vesting in 2016 [Member] | Potential Maximum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	66	'	'
Other [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	92	'	'
Other [Member] | Potential Minimum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	92	'	'
Other [Member] | Potential Maximum Units at Vesting [Member] | Cash-settleable RSU awards [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Cash-Settleable Awards, Base Units, Liability, Outstanding	92	'	'

ShareBased_Compensation_Narrat

Share-Based Compensation (Narrative) (Details) (2011 Plan [Member])	Dec. 31, 2013
In Thousands, unless otherwise specified
2011 Plan [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of Shares Available for grant	1,192

ShareBased_Compensation_ShareB

Share-Based Compensation (Share-Based Compensation Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	$4,194	[1]	$4,428	[1]	$3,058	[1]
Share-based compensation expense - Liability-based	5,347		2,916		1,335
Options [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	0		0		24
RSUs [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	3,975		4,210		2,832
Cash-settleable RSU awards [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	0		0		0
Share-based compensation expense - Liability-based	5,347		2,916		1,335
Contribution 401K in Shares Plan [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	219		218		202
General and Administrative Expense [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation expense - Equity-based	5,751		4,081		2,502
Portion Capitalized to Oil and Gas Properties [Member]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'		'		'
Share-based compensation - capitalized	$3,791		$3,263		$1,891
[1]	The portion of this share-based compensation expense that was included in general and administrative expense totaled $5,751, $4,081 and $2,502 for the same years respectively, and the portion capitalized to oil and gas properties was $3,791, $3,263 and $1,891, respectively.

ShareBased_Compensation_Unreco

Share-Based Compensation (Unrecognized Compensation Expense Expected to be Recognized in Future Periods) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Period over which expense is expected to be recognized	'1 year 4 months 24 days	'	'
RSUs [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested awards, total compensation cost not yet recognized, share-based awards other than options	$5,331	$6,320	$5,748
Period over which expense is expected to be recognized	'1 year 6 months	'	'
Cash-settleable RSU awards [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested awards, total compensation cost not yet recognized, share-based awards other than options	$7,669	$2,826	$2,498

ShareBased_Compensation_CashSe

Share-Based Compensation (Cash-Settleable RSU Awards) (Details) (Cash-settleable RSU awards [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Current and Noncurrent	$7,582	$2,446	$2,913
Other long-term liabilities [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Noncurrent	3,409	1,017	2,309
Accounts Payable and Accrued Liabilities [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Cash-Settleable Compensation Arrangement by Cash-based Arrangements Award, Liability, Current	$4,173	$1,429	$604

ShareBased_Compensation_Stock_

Share-Based Compensation (Stock Option Activity) (Details) (Options [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Options [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Number of years company issued no stock options	'3 years	'
Outstanding, shares, end of year	52	67
Exercisable, shares, end of year	52	67
Outstanding, end of year, weighted average exercise price per option	$13.63	$11.82
Exercisable, end of year weighted average exercise price per option	$13.75	$11.82
Outstanding options at end of period in years	'2 years 3 months 18 days	'2 years 8 months 12 days
Outstanding exercisable at end of period in years	'2 years 3 months 12 days	'2 years 8 months 12 days
Exercised, shares	0	'
Expired, shares	15	'

ShareBased_Compensation_Unvest

Share-Based Compensation (Unvested Restricted Stock Activity) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'
Period over which expense is expected to be recognized	'1 year 4 months 24 days
RSUs [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]	'
Outstanding at the beginning of the period	2,295
Granted	944
Vested	-754	[1]
Forfeited	-223
Outstanding at the end of the period	2,262
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'
Outstanding at the beginning of the period, Grant Date Fair Value per Share	5.58
Granted, Grant Date Fair Value per Share	3.82
Vested, Grant Date Fair Value per Share	5.1	[1]
Forfeited, Grant Date Fair Value per Share	5.37
Outstanding at the end of the period, Grant Date Fair Value per Share	5.03
Period over which expense is expected to be recognized	'1 year 6 months
Fair value of shares vested	2,689
[1]	The fair value of shares vested was $2,689.

Equity_Transactions_Details

Equity Transactions (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Feb. 28, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 12, 2014

Dec. 31, 2013

Jun. 30, 2012

Feb. 28, 2011

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

30-May-13

Dec. 31, 2013

Subsequent Event [Member]

Subsequent Event [Member]

13% Senior Notes due 2016 [Member]

13% Senior Notes due 2016 [Member]

Series A Preferred Stock [Member]

Series A Preferred Stock [Member]

Series A Preferred Stock [Member]

Series A Preferred Stock [Member]

Common Stock

Senior Notes [Member]

Senior Notes [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Convertible Preferred Stock, Shares Reserved for Future Issuance

'

'

'

'

'

42,200,000

'

'

'

'

'

'

'

Share Price

'

'

'

'

'

'

'

'

'

'

'

$47.50

$6.53

Convertible Preferred Stock, Shares Reserved to Satisfy Potential Conversion

'

12,090,000

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividend Rate, Per-Dollar-Amount

'

'

'

'

'

'

'

'

'

$5

'

'

'

Preferred Stock, Dividends, Per Share, Cash Paid

'

'

'

'

'

'

'

'

$1.25

$0.43

'

'

'

Dividends, Preferred Stock, Cash

'

'

'

'

'

'

'

'

$1,974

$679

'

'

'

Preferred Stock Dividends, Income Statement Impact

'

4,627

0

0

'

'

'

'

'

'

4,627

'

'

Stock issued during period (in shares)

10,100,000

'

'

'

'

'

'

'

'

78,947,000

'

'

'

Preferred Stock, Dividend Rate, Percentage

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

Proceeds from issuance of common stock

73,765

0

0

73,765

'

'

'

'

'

70,035

'

'

'

Underwriters over-allotment of shares (in shares)

1,100,000

'

'

'

'

'

'

'

'

1,579,000

'

'

'

Portion of Proceeds from Issuance of Common Stock Used to Repurchase Senior Notes

35,062

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of senior debt

'

'

'

'

'

'

$10,000

$31,000

'

'

'

'

'

Preferred stock, par value (in dollars per share)

'

$0.01

$0.01

'

'

'

'

'

'

'

$0.01

'

'

Preferred stock, liquidation preference (in dollars per share)

'

$50

$50

'

'

'

'

'

'

'

$50

'

'

Common stock, shares authorized

'

60,000,000

60,000,000

'

110,000,000

'

'

'

'

'

'

'

'

Common Stock, Capital Shares Reserved for Future Issuance

'

16,800,000

'

'

'

'

'

'

'

'

'

'

'

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details)	12 Months Ended
	Dec. 31, 2006
Income Tax Disclosure [Abstract]	'
Ceiling Test, Period of Aggregate Loss Basis	'3 years

Income_Taxes_Deferred_Tax_Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax asset	'	'
Federal net operating loss carryforward	$70,365	$87,774
Statutory depletion carryforward	8,880	8,184
Alternative minimum tax credit carryforward	208	208
Asset retirement obligations	1,024	3,357
Other	7,575	9,571
Total deferred tax asset	88,052	109,094
Deferred tax liability	'	'
Oil and natural gas properties	26,412	41,336
Other	32	3,375
Total deferred tax liability	26,444	44,711
Net deferred tax asset	$61,608	$64,383

Income_Taxes_Federal_Operating

Income Taxes (Federal Operating Loss Carryforwards) (Details) (Domestic Tax Authority [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	$201,042
Operating Loss Carryforwards, Valuation Allowance	167,795
2014-2019	'
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	0
2020-2022	'
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	48,986
2023-2025	'
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	65,878
2026-2028	'
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	32,714
2029-2033	'
Operating Loss Carryforwards [Line Items]	'
Federal NOL carryforwards	$53,464

Income_Taxes_Income_Tax_Reconc

Income Taxes (Income Tax Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Component of Income Tax Rate Reconciliation	'	'	'
Income tax expense computed at the statutory federal income tax rate	35.00%	35.00%	35.00%
Change in valuation allowance	0.00%	0.00%	-227.00%
Percentage depletion carryforward	-8.00%	-22.00%	-3.00%
State taxes net of federal benefit	4.00%	6.00%	0.00%
Section 162m	6.00%	22.00%	0.00%
Restricted stock and stock options	5.00%	2.00%	0.00%
Other	0.00%	4.00%	4.00%
Effective income tax rate	42.00%	47.00%	-191.00%
Components of Income Tax Expense	'	'	'
Current federal income tax benefit	$0	$0	$0
Current state income tax expense	326	110	0
Deferred federal income tax expense	2,652	1,777	13,176
Deferred state income tax expense	126	336	0
Valuation allowance	0	0	-82,459
Total income tax expense (benefit)	$3,104	$2,223	($69,283)

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Asset retirement obligations at beginning of the period	$13,301	$13,938
Accretion expense	1,785	2,253
Liabilities incurred	679	205
Liabilities settled	-457	-1,073
Liabilities related to oil and gas properties sold	-4,765	-877
Revisions to estimate	-3,811	-1,145
Asset retirement obligations at end of period	6,732	13,301
Less: current asset retirement obligations	-4,120	-2,336
Long-term asset retirement obligations at the end of the period	2,612	10,965
Restricted Investments	'	'
Restricted investments	$3,806	$3,798

Supplemental_Oil_and_Natural_G2

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Capitalized Costs) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Evaluated Properties-	'	'	'
Beginning of period balance	$1,497,010	$1,421,640	$1,316,677
Capitalized G&A	10,014	12,148	11,205
Property acquisition costs	10,885	2,075	0
Exploration costs	147,164	22,703	5,473
Development costs	36,504	38,444	88,285
End of period balance	1,701,577	1,497,010	1,421,640
Unevaluated Properties (excluded from amortization):	'	'	'
Beginning of period balance	68,776	2,603	8,106
Acquisitions	2,259	29,590	2,422
Exploration	10,767	34,674	1,372
Capitalized interest	4,410	2,109	573
Transfers to evaluated	-42,990	-200	-9,870
End of period balance	43,222	68,776	2,603
Accumulated depreciation, depletion and amortization:	'	'	'
Beginning of period balance	1,296,265	1,208,331	1,155,915
Provision charged to expense	42,251	48,524	52,416
Sale of mineral interests	82,096	39,410	0
End of period balance	1,420,612	1,296,265	1,208,331
Capitalized Costs of Unproved Properties Excluded from Amortization, Increase (Decrease) to Period Cost	($25,554)	'	'
Depletion Expense Per Physical Unit of Production	31.12	31.56	26.42
Lease Expense Per Physical Unit of Production	14	14.81	9.92
Minimum [Member]	'	'	'
Accumulated depreciation, depletion and amortization:	'	'	'
Unevaluated Property Costs Expected Evaluation Period Range	'3 years	'	'
Maximum [Member]	'	'	'
Accumulated depreciation, depletion and amortization:	'	'	'
Unevaluated Property Costs Expected Evaluation Period Range	'5 years	'	'

Supplemental_Oil_and_Natural_G3

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Proved Developed and Undeveloped Reserves) (Details)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2009

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2009

Boe

Boe

Boe

Boe

Crude Oil [Member]

Crude Oil [Member]

Crude Oil [Member]

Crude Oil [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

Natural Gas [Member]

bbl

bbl

bbl

bbl

ft3

ft3

ft3

ft3

Proved developed and undeveloped reserves:

'

'

'

'

'

'

'

'

'

'

'

'

Beginning of period

'

'

'

'

10,780,000

10,075,000

'

8,149,000

19,753,000,000

35,118,000,000

'

32,957,000,000

Revisions to previous estimates

'

'

'

'

-2,540,000

-488,000

-110,000

'

-5,351,000,000

-10,838,000,000

486,000,000

'

Purchase of reserves in place

'

'

'

'

150,000

38,000

0

'

317,000,000

115,000,000

0

'

Sale of reserves in place

'

'

'

'

-3,294,000

-504,000

-30,000

'

-4,576,000,000

-4,404,000,000

-308,000,000

'

Extensions and discoveries

'

'

'

'

7,713,000

2,636,000

3,062,000

'

10,619,000,000

3,350,000,000

7,064,000,000

'

Production

'

'

'

'

-911,000

-977,000

-996,000

'

-3,011,000,000

-3,588,000,000

-5,081,000,000

'

End of period

'

'

'

'

11,898,000

10,780,000

10,075,000

8,149,000

17,751,000,000

19,753,000,000

35,118,000,000

32,957,000,000

Beginning of period

'

'

'

'

4,955,000

5,069,000

4,503,000

'

10,680,000,000

11,605,000,000

12,715,000,000

'

End of period

'

'

'

'

5,960,000

4,955,000

5,069,000

'

9,059,000,000

10,680,000,000

11,605,000,000

'

Beginning of period

7,470,000

6,735,000

7,003,000

6,622,000

'

'

'

'

'

'

'

'

End of period

7,470,000

6,735,000

7,003,000

6,622,000

'

'

'

'

'

'

'

'

Beginning of period

'

'

'

'

5,825,000

5,006,000

3,645,000

'

9,073,000,000

23,513,000,000

20,241,000,000

'

End of period

'

'

'

'

5,938,000

5,825,000

5,006,000

'

8,692,000,000

9,073,000,000

23,513,000,000

'

Beginning of period

7,387,000

7,337,000

8,925,000

7,019,000

'

'

'

'

'

'

'

'

End of period

7,387,000

7,337,000

8,925,000

7,019,000

'

'

'

'

'

'

'

'

Supplemental_Oil_and_Natural_G4

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Proved Undeveloped Reserves) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Boe	Boe	Boe	Boe
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Proved Undeveloped Reserves (BOE), Net	14,857,000	14,072,000	'	'
Proved Developed and Proved Undeveloped Reserves (BOE), Percentage Change Between Periods	6.00%	'	'	'
Proved Undeveloped Reserves (BOE), Percentage Change Between Periods	1.00%	18.00%	'	'
Proved Undeveloped Reserves (Energy)	7,387,000	7,337,000	8,925,000	7,019,000
Proved Developed And Proved Undeveloped Reserves Extensions Discoveries And Additions	5,168,000	2,344,000	'	'
Proved Developed And Proved Undeveloped Reserves Transfers of Proved Developed Production Reserves from Development Program	-3,724,000	557,000	'	'
Proved Developed And Proved Undeveloped Reserves Sales Of Minerals In Place	-1,297,000	-1,148,000	'	'
Proved Developed And Proved Undeveloped Reserves Sales Of Minerals In Place, Percentage	18.00%	'	'	'
Proved Developed And Proved Undeveloped Reserves Revisions Of Previous Estimates Increase (Decrease)	'	2,227,000	'	'
Proved Undeveloped Reserves Conversion to Proved Developed Reserves, Percentage Transferred	51.00%	6.00%	'	'
Proved Undeveloped Reserves Conversion to Proved Developed Reserves Total Cost	'	$19	'	'
Permian Basin [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Exploratory Wells Drilled, Net Productive	26	'	'	'
Medusa fields in the Gulf of Mexico [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Undeveloped Reserves (Energy)	'	1,297,000	'	'

Supplemental_Oil_and_Natural_G5

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Summarized Average 12-month Oil and Natural Gas Prices Net of Differentials) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average 12-month price, net of differentials	5.45	4.81	5.6
Crude Oil [Member]	'	'	'
Average Sales Price and Production Costs Per Unit of Production [Line Items]	'	'	'
Average 12-month price, net of differentials	92.16	94.68	98.98

Supplemental_Oil_and_Natural_G6

Supplemental Oil and Natural Gas Reserve Data (unaudited) (Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Net Cash Flows [Abstract]	'	'	'	'
Future cash inflows	$1,193,299	$1,115,570	$1,194,079	'
Production	-357,005	-249,329	-356,653	'
Development and net abandonment	-155,667	-273,817	-268,628	'
Future net inflows before income taxes	680,627	592,424	568,798	'
Future income taxes	-68,239	-55,772	-78,813	'
Future net cash flows	612,388	536,652	489,985	'
10% discount factor	-328,442	-305,504	-219,628	'
Standardized measure of discounted future net cash flows	283,946	231,148	270,357	'
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'	'
Standardized measure at the beginning of the period	231,148	270,357	'	198,916
Sales and transfers, net of production costs	-78,661	-84,044	-107,297	'
Net change in sales and transfer prices, net of production costs	-46,088	47,261	125,518	'
Net change due to purchases and sales of in place reserves	-145,711	-35,665	1,275	'
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	212,431	53,446	22,598	'
Changes in future development cost	153,983	39,815	-83,110	'
Revisions of quantity estimates	-68,958	-77,322	-949	'
Accretion of discount	25,010	30,989	68,384	'
Net change in income taxes	1,751	13,969	-32,918	'
Changes in production rates, timing and other	-959	-27,658	77,940	'
Aggregate change	52,798	-39,209	71,441	'
Standardized measure at the end of the period	$283,946	$231,148	$270,357	$198,916

Other_Details

Other (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

0 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2013

Sep. 30, 2012

Mar. 31, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 07, 2014

Dec. 31, 2013

Apr. 30, 2012

Apr. 11, 2014

Aug. 01, 2013

Feb. 17, 2014

Feb. 17, 2014

Reagan and Upton Counties Acreage Purchase [Member]

Borden County Acreage Purchase [Member]

Borden County Acreage Purchase [Member]

Southern Reagan County, Texas [Member]

Medusa Field [Member]

Medusa Spar, LLC [Member]

Medusa Fields, Medusa Spar LLC, And Gulf Of Mexico Shelf Properties [Member]

Swan Lake Field [Member]

Habanero Field (Garden Banks Block 341) [Member]

Callon Entrada [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Cactus 1 Rig [Member]

Cactus 1 Rig [Member]

Patterson Rig [Member]

Patterson Rig [Member]

Cactus 2 Rig [Member]

acre

acre

acre

acre

Permian Basin [Member]

Subsequent Event [Member]

Permian Basin [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Horizontal Drilling Rig [Member]

Permian Basin [Member]

Horizontal Drilling Rig [Member]

Permian Basin [Member]

Permian Basin [Member]

Horizontal Drilling Rig [Member]

Horizontal Drilling Rig [Member]

Horizontal Drilling Rig [Member]

Operating Leased Assets [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Bargain Purchase, Gain Recognized, Amount

'

'

'

'

'

'

'

'

'

'

'

'

$5,041

'

'

'

'

'

'

'

Gain (Loss) on Sale of Assets and Asset Impairment Charges

-1,707

-1,177

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contracted drilling rig, term (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'2 years

'1 year

'

'2 years

Contract Termination Liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,055

'

Operating lease payments

12,860

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease payments in 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,954

'

'

'

'

'

Lease payments in 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,308

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due in Three Years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,295

'

'

'

'

'

Contractual Obligation, Due in Next Twelve Months

'

'

'

'

'

'

'

'

'

'

'

'

'

19,732

'

'

'

'

'

'

Contractual Obligation, Due in Second Year

'

'

'

'

'

'

'

'

'

'

'

'

'

18,250

'

'

'

'

'

'

Contractual Obligation, Due in Third Year

'

'

'

'

'

'

'

'

'

'

'

'

'

4,500

'

'

'

'

'

'

Gas and Oil Area, Developed and Undeveloped, Gross

'

'

'

2,468

8,095

16,233

2,319

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas and Oil Area, Developed and Undeveloped, Net

'

'

'

2,186

6,964

14,653

1,762

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Consideration Transferred

'

'

'

11,000

4,835

14,538

12,012

'

'

'

'

'

'

'

'

'

'

'

'

'

Divestiture of Business, Percentage Of Business Sold

'

'

'

'

'

'

'

15.00%

10.00%

'

69.00%

11.25%

'

'

'

'

'

'

'

'

Divestiture of Business, Sales Price

'

'

'

'

'

'

'

'

'

$88,000

$2,000

$39,410

'

'

'

'

'

'

'

'

Other_Property_Acquisitions_an

Other (Property Acquisitions and Disposals) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Mar. 31, 2012	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2013
	Reagan and Upton Counties Acreage Purchase [Member]	Borden County Acreage Purchase [Member]	Borden County Acreage Purchase [Member]	Southern Reagan County, Texas [Member]	Medusa Field [Member]	Medusa Spar, LLC [Member]	Medusa Fields, Medusa Spar LLC, And Gulf Of Mexico Shelf Properties [Member]	Swan Lake Field [Member]	Habanero Field (Garden Banks Block 341) [Member]	Southern Portion of Midland Basin [Member]
	acre	acre	acre	acre						bbl
										Oil_well
Significant Acquisitions and Disposals [Line Items]	'	'	'	'	'	'	'	'	'	'
Gas and Oil Area, Developed and Undeveloped, Gross	2,468	8,095	16,233	2,319	'	'	'	'	'	'
Gas and Oil Area, Developed and Undeveloped, Net	2,186	6,964	14,653	1,762	'	'	'	'	'	'
Business Combination, Consideration Transferred	$11,000	$4,835	$14,538	$12,012	'	'	'	'	'	'
Divestiture of Business, Percentage Of Business Sold	'	'	'	'	15.00%	10.00%	'	69.00%	11.25%	'
Divestiture of Business, Sales Price	'	'	'	'	'	'	$88,000	$2,000	$39,410	'
Productive Oil Wells, Number of Wells, Gross	'	'	'	'	'	'	'	'	'	7
Proved Developed Reserves (Volume)	'	'	'	'	'	'	'	'	'	1,301,000

Summarized_Quarterly_Financial2

Summarized Quarterly Financial Information (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
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$26,471	$30,797	$22,760	$22,541	$28,677	$27,402	$25,360	$29,294	$102,569	$110,733	$127,644
Income from operations	2,464	6,345	957	898	2,652	2,563	2,759	2,716	10,664	10,690	39,622
Net income (loss)	3,264	1,082	758	-800	'	'	'	'	4,304	2,747	106,396
Income (loss) available to common shares	$1,291	($892)	$78	($800)	($435)	($1,105)	$3,799	$488	($323)	$2,747	$106,396
Income (loss) per common share - basic	$0.03	($0.02)	$0	($0.02)	($0.01)	($0.03)	$0.10	$0.01	($0.01)	$0.07	$2.81
Income (loss) per common share - diluted	$0.03	($0.02)	$0	($0.02)	($0.01)	($0.03)	$0.09	$0.01	($0.01)	$0.07	$2.76