Chaparral Energy (CHAP) 10-K 31 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013	Mar. 25, 2014	Mar. 25, 2014	Mar. 25, 2014	Mar. 25, 2014	Mar. 25, 2014	Mar. 25, 2014
			Class A Common Stock	Class B Common Stock	Class C Common Stock	Class E Common Stock	Class F Common Stock	Class G Common Stock
Entity Information	'	'	'	'	'	'	'	'
Entity Registrant Name	'Chaparral Energy, Inc.	'	'	'	'	'	'	'
Entity Central Index Key	'0001346980	'	'	'	'	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'	'	'	'	'
Entity Filer Category	'Non-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	'	'	366,685	344,859	209,882	504,276	1	2
Entity Well-known Seasoned Issuer	'No	'	'	'	'	'	'	'
Entity Voluntary Filers	'Yes	'	'	'	'	'	'	'
Entity Current Reporting Status	'No	'	'	'	'	'	'	'
Entity Public Float	'	$0	'	'	'	'	'	'

Consolidated_balance_sheets

Consolidated balance sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets	'	'
Cash and cash equivalents	$48,595	$29,819
Accounts receivable, net	96,515	77,307
Inventories, net	16,137	10,510
Prepaid expenses	3,998	3,465
Derivative instruments	2,152	42,516
Deferred income taxes	9,260	0
Total current assets	176,657	163,617
Property and equipmentbat cost, net	69,426	71,290
Oil and natural gas properties, using the full cost method:	'	'
Proved	3,258,661	2,860,611
Unevaluated (excluded from the amortization base)	321,477	162,921
Accumulated depreciation, depletion, amortization and impairment	-1,470,090	-1,290,356
Total oil and natural gas properties	2,110,048	1,733,176
Derivative instruments	6,403	517
Other assets	35,348	38,952
Total assets	2,397,882	2,007,552
Liabilities and stockholders' equity	'	'
Accounts payable and accrued liabilities	134,811	101,598
Accrued payroll and benefits payable	24,246	19,655
Accrued interest payable	24,225	24,131
Revenue distribution payable	25,138	18,152
Current maturities of long-term debt and capital leases	5,334	3,746
Derivative instruments	8,234	436
Deferred income taxes	0	26,872
Total current liabilities	221,988	194,590
Long-term debt and capital leases, less current maturities	1,557,528	1,289,656
Derivative instruments	0	2,192
Stock-based compensation	4,942	3,042
Asset retirement obligations	53,305	46,314
Deferred income taxes	62,855	8,901
Commitments and contingencies (Note 14)	'	'
Stockholders' equity:	'	'
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	424,377	422,434
Retained earnings	72,873	17,186
Accumulated other comprehensive income, net of taxes	0	23,223
Total stockholders' equity	497,264	462,857
Total liabilities and stockholders' equity	2,397,882	2,007,552
Class A Common Stock	'	'
Stockholders' equity:	'	'
Common stock	0	0
Class B Common Stock	'	'
Stockholders' equity:	'	'
Common stock	4	4
Class C Common Stock	'	'
Stockholders' equity:	'	'
Common stock	2	2
Class D Common Stock	'	'
Stockholders' equity:	'	'
Common stock	3	3
Class E Common Stock	'	'
Stockholders' equity:	'	'
Common stock	5	5
Class F Common Stock	'	'
Stockholders' equity:	'	'
Common stock	0	0
Class G Common Stock	'	'
Stockholders' equity:	'	'
Common stock	$0	$0

Consolidated_balance_sheets_Pa

Consolidated balance sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Preferred stock, shares authorized	600,000	600,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Class A Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	70,117	67,991
Common stock, shares outstanding	70,117	67,991
Class B Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	357,882	357,882
Common stock, shares outstanding	357,882	357,882
Class C Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	209,882	209,882
Common stock, shares outstanding	209,882	209,882
Class D Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	279,999	279,999
Common stock, shares outstanding	279,999	279,999
Class E Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	504,276	504,276
Common stock, shares outstanding	504,276	504,276
Class F Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	1	1
Common stock, shares issued	1	1
Common stock, shares outstanding	1	1
Class G Common Stock	'	'
Common stock, par value	0.01	0.01
Common stock, shares authorized	3	3
Common stock, shares issued	3	3
Common stock, shares outstanding	3	3

Consolidated_statements_of_ope

Consolidated statements of operations (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Commodity sales	$591,674	$509,503	$530,041
Gain (loss) from oil hedging activities	37,134	46,746	-27,452
Other revenues	0	0	4,070
Total revenues	628,808	556,249	506,659
Costs and expenses:	'	'	'
Lease operating	139,771	130,960	121,420
Production taxes	33,266	32,003	34,321
Depreciation, depletion & amortization	192,426	169,307	146,083
Loss on impairment of other assets	3,490	2,000	0
General and administrative	53,883	49,812	42,056
Other expenses	0	0	3,448
Total costs and expenses	422,836	384,082	347,328
Operating income	205,972	172,167	159,331
Non-operating income (expense):	'	'	'
Interest expense	-96,876	-98,402	-96,720
Non-hedge derivative (losses) gains	-21,635	49,685	34,408
Loss on extinguishment of debt	0	-21,714	-20,592
Other income	1,075	504	1,545
Net non-operating expense	-117,436	-69,927	-81,359
Income before income taxes	88,536	102,240	77,972
Income tax expense	32,849	37,837	35,924
Net income	$55,687	$64,403	$42,048

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
Comprehensive income	'	'	'
Net income	$55,687	$64,403	$42,048
Other comprehensive (loss) income	'	'	'
Reclassification adjustment for hedge (gains) losses included in gain (loss) from oil hedging activities in the consolidated statements of operations	-37,134	-46,746	27,452
Income tax expense (benefit) related to other comprehensive income (loss)	13,911	18,123	-10,580
Other comprehensive (loss) income, net of tax	-23,223	-28,623	16,872
Comprehensive income	$32,464	$35,780	$58,920

Consolidated_statements_of_sto

Consolidated statements of stockholders' equity Statement (USD $)	Total	Common stock	Additional paid in capital	Retained earnings (accumulated deficit)	Accumulated other comprehensive income
In Thousands, except Share data
Stockholders' equity at Dec. 31, 2010	$363,557	$14	$417,834	($89,265)	$34,974
Common stock, shares outstanding at Dec. 31, 2010	'	1,403,389	'	'	'
Restricted stock issuances	'	17,642	'	'	'
Restricted stock forfeitures	'	-2,295	'	'	'
Restricted stock repurchased	'	-528	'	'	'
Stock-based compensation	4,137	'	4,137	'	'
Modification of Time Vested awards to liability	-2,640	'	-2,640	'	'
Time Vested awards settled in restricted stock	39	'	39	'	'
Net income	42,048	'	'	42,048	'
Other comprehensive income (loss), net of tax	16,872	'	'	'	16,872
Stockholders' equity at Dec. 31, 2011	424,013	14	419,370	-47,217	51,846
Common stock, shares outstanding at Dec. 31, 2011	'	1,418,208	'	'	'
Restricted stock issuances	'	17,494	'	'	'
Restricted stock forfeitures	'	-14,199	'	'	'
Restricted stock repurchased	'	-1,469	'	'	'
Stock-based compensation	2,463	'	2,463	'	'
Modification of Time Vested awards to liability	0	'	'	'	'
Time Vested awards settled in restricted stock	601	'	601	'	'
Net income	64,403	'	'	64,403	'
Other comprehensive income (loss), net of tax	-28,623	'	'	'	-28,623
Stockholders' equity at Dec. 31, 2012	462,857	14	422,434	17,186	23,223
Common stock, shares outstanding at Dec. 31, 2012	'	1,420,034	'	'	'
Restricted stock issuances	'	8,056	'	'	'
Restricted stock forfeitures	'	-4,905	'	'	'
Restricted stock repurchased	'	-1,025	'	'	'
Stock-based compensation	1,121	'	1,121	'	'
Modification of Time Vested awards to liability	0	'	'	'	'
Time Vested awards settled in restricted stock	822	'	822	'	'
Net income	55,687	'	'	55,687	'
Other comprehensive income (loss), net of tax	-23,223	'	'	'	-23,223
Stockholders' equity at Dec. 31, 2013	$497,264	$14	$424,377	$72,873	$0
Common stock, shares outstanding at Dec. 31, 2013	'	1,422,160	'	'	'

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	$55,687	$64,403	$42,048
Adjustments to reconcile net income to net cash provided by operating activities	'	'	'
Depreciation, depletion & amortization	192,426	169,307	146,083
Loss on impairment of other assets	3,490	2,000	0
Deferred income taxes	31,734	37,719	35,745
(Gain) loss on hedge reclassification adjustments	-37,134	-46,746	27,452
Non-hedge derivative losses (gains)	21,635	-49,685	-34,408
Loss on extinguishment of debt	0	21,714	20,592
Net gain on sale of assets	-670	-149	-1,284
Other	2,308	2,864	3,057
Change in assets and liabilities	'	'	'
Accounts receivable	-21,216	-12,502	-4,762
Inventories	-5,923	-2,304	328
Prepaid expenses and other assets	811	2,360	1,583
Accounts payable and accrued liabilities	9,977	3,988	16,519
Revenue distribution payable	6,986	-2,648	3,577
Stock-based compensation	3,942	1,679	3,086
Net cash provided by operating activities	264,053	192,000	259,616
Cash flows from investing activities	'	'	'
Expenditures for property, plant, and equipment	-491,022	-506,787	-339,863
Acquisition of a business	-153,858	0	0
Proceeds from asset dispositions	111,246	46,246	38,356
Settlement of non-hedge derivative instruments	19,113	37,274	-23,491
Other	-601	21	0
Net cash used in investing activities	-515,122	-423,246	-324,998
Cash flows from financing activities	'	'	'
Proceeds from long-term debt	297,797	208,561	21,724
Repayment of long-term debt	-52,100	-183,482	-24,785
Proceeds from Senior Notes	0	556,750	400,000
Repayment of Senior Notes	0	-325,000	-325,000
Proceeds from sale and leaseback of assets	24,500	0	0
Principal payments under capital lease obligations	-352	-10	-120
Payment of debt issuance costs and other financing fees	0	-14,516	-11,858
Payment of debt extinguishment costs	0	-15,827	-15,101
Net cash provided by financing activities	269,845	226,476	44,860
Net increase (decrease) in cash and cash equivalents	18,776	-4,770	-20,522
Cash and cash equivalents at beginning of period	29,819	34,589	55,111
Cash and cash equivalents at end of period	$48,595	$29,819	$34,589

Nature_of_operations_and_summa

Nature of operations and summary of significant accounting policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Nature of operations and summary of significant accounting policies	'
	Nature of operations and summary of significant accounting policies
	Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, and Kansas.
	A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
	Principles of consolidation
	The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“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.
	The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.
	Reclassifications
	Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.
	Cash and cash equivalents
	We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2013, cash with a recorded balance totaling $46,692 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.
	Accounts receivable
	We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
	We write off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2013, 2012, and 2011 was $498, $731, and $179, respectively. Accounts receivable consisted of the following at December 31:
		2013			2012
	Joint interests	$	31,335		$	19,282
	Accrued commodity sales	60,768			50,814
	Derivative settlements	4,616			8,013
	Other	1,392			472
	Allowance for doubtful accounts	(1,596		)	(1,274		)
		$	96,515		$	77,307
	Inventories
	Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. We recorded expense of $0, $0, and $602 for the years ended December 31, 2013, 2012, and 2011, respectively, to reflect changes in the valuation allowance. Inventories consisted of the following at December 31:
		2013			2012
	Equipment inventory	$	13,657		$	8,047
	Commodities	3,186			3,175
	Inventory valuation allowance	(706		)	(712		)
		$	16,137		$	10,510
	Property and equipment
	Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently.
	Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows:
	Furniture and fixtures			10 years
	Automobiles and trucks			5 years
	Machinery and equipment	10	—	20 years
	Office and computer equipment	5	—	10 years
	Building and improvements	10	—	40 years
	Oil and natural gas properties
	Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, capitalized interest on qualified projects and other internal costs directly attributable to these activities.
	The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work in progress costs are included in unevaluated oil and natural gas properties and as of December 31, 2013, include $196,227 of capital costs incurred for undeveloped acreage, $115,828 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination. As of December 31, 2012, work in progress costs included $64,840 of capital costs incurred for undeveloped acreage, $84,183 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $13,898 for wells and facilities in progress pending determination.
	Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
	Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), net of tax considerations, plus the cost of unproved properties not being amortized.
	Our estimates of oil and natural gas reserves as of December 31, 2013, 2012, and 2011 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). As of December 31, 2013, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $96.78 per Bbl of oil, $3.67 per Mcf of natural gas and $32.53 per Bbl of natural gas liquids for the year ended December 31, 2013.
	A decline in oil and natural gas prices subsequent to December 31, 2013 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
	Assets held for sale
	Assets are classified as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. The classification is only made when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated, and measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and natural gas properties.
	In the fourth quarter of 2012, we finalized a plan to dispose of certain of our drilling rigs by sale. As a result of determining fair value less costs to sell on these assets, an impairment loss was recorded in the amount of $1,500 preceding classification as held for sale. In the third quarter of 2013, we reassessed the fair value of the drilling rigs classified as held for sale and recorded an additional impairment loss of $1,090.
	In late 2013, market conditions changed and hence the timing of the ultimate disposal of the drilling rigs became uncertain. Accordingly, we reclassified the drilling rigs to property and equipment in the consolidated balance sheets. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depreciation that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, we recognized an additional loss of $2,400 in the fourth quarter of 2013. All impairment losses related to assets held for sale are included in loss on impairment of other assets in the consolidated statement of operations. We have reclassified our consolidated balance sheets as of December 31, 2012, to reflect the drilling rigs as assets held and used in order to conform to the current year presentation.
	Impairment of long-lived assets
	Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
	In addition to the impairments discussed above, during 2012, we recognized $500 of impairment losses primarily related to drill pipe held and used which was recorded in loss on impairment of other assets in the consolidated statements of operations.
	Deferred income taxes
	Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.
	Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
	If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2013 and 2012, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.
	Tax years beginning with 1998 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
	Derivative transactions
	We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.
	Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and is reclassified into income as the hedged transactions occur. As of December 31, 2013, all amounts related to de-designated cash flow hedges have been reclassified into earnings.
	We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 6—Derivative instruments” for additional information regarding our derivative transactions.
	Fair value measurements
	Fair value is defined by the FASB 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. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
	Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 7—Fair value measurements” for additional information regarding our fair value measurements.
Valuation of business combinations
In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using a market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting.
Asset retirement obligations
We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells at the end of their productive lives and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 8—Asset retirement obligations” for additional information regarding our asset retirement obligations.
Environmental liabilities
We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2013 and 2012, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.
Revenue recognition
Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products or services are recognized at the time of delivery of materials or performance of service.
Gas balancing
In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2013 and 2012, our aggregate imbalance due to under production was approximately 2,449 MMcf and 2,690 MMcf, respectively. As of December 31, 2013 and 2012, our aggregate imbalance due to over production was approximately 1,553 MMcf and 1,658 MMcf, respectively, and a liability for gas imbalances of $1,588 and $1,984, respectively, was included in accounts payable and accrued liabilities.
Stock-based compensation
Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.
The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.
The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.
We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.
The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.
The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.
See “Note 10—Stock-based compensation” for additional information relating to stock-based compensation.
Recently adopted accounting pronouncements
Balance Sheet Offsetting. In December 2011, the FASB issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, additional guidance was issued which narrows the scope of the disclosure requirements to derivatives, securities borrowings, and securities lending transactions that are either offset or subject to a master netting arrangement. This guidance, which was effective and adopted by us in the first quarter of 2013, resulted in additional disclosures but had no financial impact.
Presentation of Comprehensive Income. In February 2013, the FASB issued authoritative guidance that requires disclosures of the amounts reclassified out of AOCI by component, including the respective line items of net income if the amount is required to be reclassified to net income in its entirety in the same reporting period. This additional guidance was effective and adopted by us in the first quarter of 2013. As our entire balance in AOCI consists of deferred hedge gains, implementation of the guidance had no significant impact on our financial statement presentation and disclosures.
Recently issued accounting pronouncements
Other Expenses. In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We have assessed the impact that this fee and the adoption of the related authoritative guidance will have on our consolidated financial statements and determined the impact to be immaterial.

Supplemental_disclosures_to_th

Supplemental disclosures to the consolidated statements of cash flows	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]	'
Supplemental disclosures to the consolidated statements of cash flows	'
	Supplemental disclosures to the consolidated statements of cash flows
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year ended December 31,
		2013			2012			2011
	Net cash provided by operating activities included:
	Cash payments for interest	$	107,122		$	103,350		$	85,222
	Interest capitalized	(15,995		)	(4,437		)	(2,379		)
	Cash payments for interest, net of amounts capitalized	$	91,127		$	98,913		$	82,843
	Cash payments for income taxes	$	641		$	255		$	179
	Non-cash investing activities included:
	Asset retirement obligation additions and revisions	$	9,036		$	1,079		$	2,522
	Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities	$	27,875		$	24,280		$	(14,667	)
	Non-cash financing activities included:
	Modification of Time Vesting equity awards to liability plan	$	—		$	—		$	2,640

Acquisitions_and_divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions and Divestitures	'
	Acquisitions and divestitures
	2013 Acquisition and divestitures
	Cabot Acquisition. In late 2013, we acquired additional oil and natural gas properties consisting of approximately 131,000 (66,000 net) acres in the Panhandle Marmaton play from Cabot Oil & Gas Corporation for approximately $153,858, net of pre-closing purchase price adjustments and subject to post closing adjustments ( the “Cabot Acquisition”). The Cabot Acquisition expanded our presence in the Panhandle Marmaton play, adding oil and natural gas reserves and production to our existing asset base in this area.
	Our acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the December 18, 2013 acquisition date, which was the date on which we obtained control of the properties. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See “Note 7—Fair value measurements” for additional discussion of the measurement inputs.
	We estimated the consideration paid for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. Acquisition-related costs of $951 have been expensed as incurred in general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013. Due to the timing of the acquisition, the effect of the acquired properties on our revenues and earnings for the year ended December 31, 2013 was not material.
	The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013. The purchase price allocation is preliminary and subject to adjustment upon the final closing settlement that we expect to complete during the second quarter of 2014.
	Consideration paid
	Cash, net of purchase price adjustments	$	153,858
	Fair value of identifiable assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved	$	67,275
	Unevaluated	87,663
	Asset retirement obligations	(1,080		)
	Fair value of net identifiable assets acquired	$	153,858
	The following unaudited pro forma combined results of operations for the years ended December 31, 2013 and 2012 are presented as though we completed the Cabot Acquisition as of January 1, 2012. The pro forma combined results of operations for the years ended December 31, 2013 and 2012 have been prepared by adjusting the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by us in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects.
		Year ended December 31,
		2013			2012
	Revenues	$	690,564		$	599,344
	Operating expenses	$	448,751		$	402,677
	Net income	$	76,552		$	78,089
	Sale of Certain Non-Strategic Oil and Natural Gas Properties. During 2013, we sold various oil and natural gas properties for total cash proceeds of approximately $109,710 subject to post-closing adjustments. These included properties in Creek, Love and Carter counties, Oklahoma, that were sold for approximately $61,440 and properties in Texas County, Oklahoma, that were sold for approximately $17,800. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.
	2012 Divestitures
	Sale of Certain Mature Oil and Natural Gas Properties. On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.
	2011 Divestitures
	Sale of Rocky Mountain Properties. On November 28, 2011, we sold certain non-strategic oil and natural gas properties located in our Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33,100. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.
	Sale of Remaining Assets of Green Country Supply, Inc. On November 7, 2011, we sold substantially all the remaining assets of Green Country Supply, Inc., a wholly owned subsidiary, for a cash price of $4,433. We recorded a gain on the sale of $2,630, which is included in “Other income” on the consolidated statements of operations.

Property_and_equipment

Property and equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property and equipment	'
	Property and equipment
	Major classes of property and equipment consist of the following at December 31:
		2013		2012
	Furniture and fixtures	$	2,405	$	2,327
	Automobiles and trucks	14,053		13,618
	Machinery and equipment	67,337		67,291
	Office and computer equipment	14,452		10,603
	Building and improvements	26,798		26,051
		125,045		119,890
	Less accumulated depreciation and amortization	64,350		55,356
		60,695		64,534
	Land	8,731		6,756
		$	69,426	$	71,290
	Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:
		2013		2012
	Office and computer equipment	$	1,926	$	1,926
	Machinery and equipment	642		642
		2,568		2,568
	Less accumulated depreciation and amortization	2,305		2,241
		$	263	$	327

Longterm_debt

Long-term debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-term debt	'
	Long-term debt
	As of the dates indicated, long-term debt consists of the following:
			December 31,
			2013		2012
	9.875% Senior Notes due 2020, net of discount of $5,444 and $5,969, respectively		$	294,556	$	294,031
	8.25% Senior Notes due 2021		400,000		400,000
	7.625% Senior Notes due 2022, including premium of $5,719 and $6,631, respectively		555,719		556,631
	Senior secured revolving credit facility		272,000		25,000
	Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property		11,202		12,596
	Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.87% to 6.79%, due January 2014 through February 2018; collateralized by automobiles, machinery and equipment		5,235		5,144
	Capital lease obligations		24,150		—
			1,562,862		1,293,402
	Less current maturities		5,334		3,746
			$	1,557,528	$	1,289,656
	Maturities of long-term debt and capital leases, excluding premiums or discounts on our senior notes, are as follows as of December 31, 2013:
	2014		$	5,334
	2015		4,837
	2016		3,757
	2017		275,250
	2018		3,302
	2019 and thereafter		1,270,107
			$	1,562,587
	Senior Notes
	The senior notes, which, as of December 31, 2013, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The Senior Notes are redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.
	Interest on the Senior Notes is payable semi-annually, and the principal is due upon maturity. Certain of the Senior Notes were issued at a discount or a premium which is amortized to interest expense over the term of the respective series of Senior Notes. Net amortization of the (premium) discount was $(387), $439, and $668 during the years ended December 2013, 2012 and 2011, respectively.
	We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:
	•	incur or guarantee additional debt and issue certain types of preferred stock;
	•	pay dividends on capital stock or redeem, repurchase, or retire capital stock or subordinated debt;
	•	make investments;
	•	incur liens on assets;
	•	create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
	•	engage in transactions with affiliates;
	•	sell assets, including capital stock of our subsidiaries;
	•	consolidate, merge or transfer assets; and
	•	enter into other lines of business.
	If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.
	Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Chaparral Biofuels, LLC.
	2012 Activity. On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the issuance to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. Costs totaling $21,714 associated with the refinancing of our 8.875% Senior Notes, including repurchase or redemption-related fees and the write-off of deferred financing costs and unaccreted discount, were recorded as a loss on extinguishment of debt in 2012.
	On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2012. The net proceeds from the additional 7.625% Senior Notes issuance were used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes.
	2011 Activity. On February 22, 2011, we issued $400,000 aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. Costs totaling $20,592 associated with the refinancing of our 8.5% Senior Notes, including repurchase and redemption-related fees and the write-off of deferred financing costs, were recorded as a loss on extinguishment of debt in 2011.
	Senior secured revolving credit facility
	In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. The Thirteenth Amendment, effective October 29, 2013, amended our senior secured revolving credit facility to (a) increase our borrowing base from $500,000 to $550,000, (b) automatically increase the borrowing base to $600,000 upon the consummation of the Cabot Acquisition, (c) allow for the incurrence of $300,000 of unsecured senior or subordinated debt meeting the definition of “Additional Permitted Debt” under our senior secured revolving credit facility, (d) permit entering into swap agreements on production from to-be-acquired properties, including the assets to be acquired in the Cabot Acquisition, in notional amounts up to 80% of anticipated proved developed producing production therefrom if otherwise meeting additional necessary requirements under our senior secured revolving credit facility, and (e) increase permitted other debt from $40,000 to $50,000.
	Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Effective December 18, 2013, our borrowing base was increased to $600,000. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base.
	Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2013 was subject to the Eurodollar rate.
	The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin that varies depending on our utilization percentage. During 2013, the applicable margin varied from 1.50% to 1.75%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than 3 months or every 3 months.
	Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1.00%, plus a margin that varies depending on our utilization percentage. During 2013, the applicable margin varied from 0.50% to 0.75%.
	Commitment fees of 0.375% to 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.
	Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:
	•	incur additional indebtedness;
	•	create or incur additional liens on our oil and natural gas properties;
	•	pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;
	•	make investments in or loans to others;
	•	change our line of business;
	•	enter into operating leases;
	•	merge or consolidate with another person, or lease or sell all or substantially all of our assets;
	•	sell, farm-out or otherwise transfer property containing proved reserves;
	•	enter into transactions with affiliates;
	•	issue preferred stock;
	•	enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;
	•	enter into or terminate certain swap agreements;
	•	amend our organizational documents; and
	•	amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.
	Our senior secured revolving credit facility, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. We believe we were in compliance with all covenants under our senior secured revolving credit facility as of December 31, 2013.
Our senior secured revolving credit facility also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.
If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 30 days.
Debt issuance costs
The costs that we incur to issue debt includes underwriting and other professional  fees. These costs are initially capitalized and are included in “Other assets” in the consolidated balance sheets. The balance of unamortized issuance costs was $23,273 and  $25,410 as of December 31, 2013 and 2012, respectively. These costs are amortized as a charge to interest expense using the effective interest method. We recorded amortization of $2,197, $1,694 and $1,608 for the years ended December 31, 2013, 2012 and 2011, respectively.
Capital leases
We entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3,181 annually.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative instruments	'
	Derivative instruments
	Overview
	Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, enhanced price swaps, costless collars, put options, and basis protection swaps. See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.
	For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
	Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.
	Put options may be purchased from the counterparty by our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.
	We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.
	We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
	We enter into crude oil derivative contracts for a portion of our natural gas liquids production. The following table summarizes our crude oil derivatives outstanding as of December 31, 2013:
						Weighted average fixed price per Bbl
	Period and type of contract		Volume			Swaps				Sold puts				Purchased puts		Sold calls
			MBbls
	2014
	Swaps		961			$	93.5			$	—			$	—	$	—
	Three-way collars		2,400			$	—			$	75.5			$	93.25	$	101.94
	Enhanced swaps		840			$	98.62			$	80			$	—	$	—
	Put spread enhanced swaps		2,480			$	93.76			$	80			$	60	$	—
	Purchased puts		840			$	—			$	—			$	60	$	—
	2015
	Enhanced swaps		5,578			$	93.14			$	80			$	—	$	—
	The following tables summarize our natural gas derivative instruments outstanding as of December 31, 2013:
	Period and type of contract		Volume			Weighted
			BBtu			average
						fixed price
						per MMBtu
	2014
	Natural gas swaps		21,100			$	4.03
	Natural gas basis protection swaps		21,550			$	0.24
	2015
	Natural gas swaps		16,800			$	4.21
	Natural gas basis protection swaps		2,400			$	0.18
	Effect of derivative instruments on the consolidated balance sheets
	All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 7—Fair value measurements” for additional information. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.
		As of December 31, 2013												As of December 31, 2012
		Assets				Liabilities				Net value				Assets		Liabilities			Net value
	Natural gas swaps	$	1,457			$	(3,706	)		$	(2,249	)		$	13,642	$	(1,487	)	$	12,155
	Oil swaps	112				(2,807		)		(2,695		)		4,957		(1,339		)	3,618
	Oil collars	2,776				(4		)		2,772				27,411		(1,180		)	26,231
	Oil enhanced swaps	6,988				(6,212		)		776				—		—			—
	Oil purchased puts (1)	74				—				74				—		—			—
	Natural gas basis differential swaps	1,706				(63		)		1,643				—		(1,599		)	(1,599		)
	Total derivative instruments	13,113				(12,792		)		321				46,010		(5,605		)	40,405
	Less:
	Netting adjustments (2)	4,558				(4,558		)		—				2,977		(2,977		)	—
	Current portion asset (liability)	2,152				(8,234		)		(6,082		)		42,516		(436		)	42,080
		$	6,403			$	—			$	6,403			$	517	$	(2,192	)	$	(1,675	)
	___________
	-1	Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.
	-2	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
	Derivative settlements outstanding were as follows at December 31:
		2013				2012
	Derivative settlements receivable included in accounts receivable	$	4,616			$	8,013
	Derivative settlements payable included in accounts payable and accrued liabilities	$	377			$	41
	Effect of derivative instruments on the consolidated statements of operations
	We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations.
	We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through AOCI. Gain (loss) from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains (losses) on discontinued oil hedges from AOCI into net income. As of December 31, 2013, there are no longer any deferred gains in AOCI as all the previously deferred gains (losses) have been reclassified into earnings upon the sale of the hedged production.
	Non-hedge derivative (losses) gains in the consolidated statements of operations are comprised of the following:
			2013				2012				2011
	Change in fair value of commodity price swaps		$	(20,717	)		$	(8,440	)		$	50,004
	Change in fair value of collars		(23,459		)		21,182				3,540
	Change in fair value of enhanced swaps and put options		186				—				—
	Change in fair value of natural gas basis differential contracts		3,242				(331		)		4,355
	Receipts from (payments on) settlement of commodity price swaps		5,122				28,716				(16,801		)
Receipts from settlement of collars		14,548				10,229				1,250
Payments on settlement of natural gas basis differential contracts		(557		)		(1,671		)		(7,940		)
		$	(21,635	)		$	49,685			$	34,408
Any premiums paid on derivative contracts will be included in non-hedge derivative gains (losses) as the derivative contracts settle.

Fair_value_measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair value measurements	'
	Fair value measurements
	Recurring fair value measurements
	Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 6—Derivative instruments”). We have no Level 1 assets or liabilities as of December 31, 2013 or December 31, 2012. Our derivative contracts classified as Level 2 as of December 31, 2013 and December 31, 2012 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.
	As of December 31, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. As of December 31, 2012, our derivative contracts classified as Level 3 consisted of three-way collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness.
	All derivative instruments are discounted further using a rate that incorporates our nonperformance risk for derivative liabilities and our counterparties’ nonperformance risk for derivative assets. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having similar maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of December 31, 2013 and December 31, 2012, the rate reflecting our nonperformance risk was 1.75% and 1.50%, respectively. The weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 0.31% and 0.32% as of December 31, 2013 and December 31, 2012, respectively.
	The fair value hierarchy for our financial assets and liabilities is shown by the following table:
		As of December 31, 2013												As of December 31, 2012
		Derivative				Derivative				Net assets				Derivative				Derivative				Net assets
		assets				liabilities				(liabilities)				assets				liabilities				(liabilities)
	Significant other observable inputs (Level 2)	$	3,275			$	(6,576	)		$	(3,301	)		$	18,599			$	(4,425	)		$	14,174
	Significant unobservable inputs (Level 3)	9,838				(6,216		)		3,622				27,411				(1,180		)		26,231
	Netting adjustments (1)	(4,558		)		4,558				—				(2,977		)		2,977				—
		$	8,555			$	(8,234	)		$	321			$	43,033			$	(2,628	)		$	40,405
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
	Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31 were:
	Net derivative assets		2013				2012
	Beginning balance		$	26,231			$	5,049
	Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains		(8,725		)		31,411
	Purchases		664				—
	Settlements received		(14,548		)		(10,229		)
	Ending balance		$	3,622			$	26,231
	Gains relating to instruments still held at the reporting date included in non-hedge derivative gains for the period		$	3,177			$	21,534
	Nonrecurring fair value measurements
	Allocation of purchase price in business combinations. The estimated fair values of proved oil and gas properties and asset retirement obligations assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of these assumptions, they are considered Level 3 inputs under the fair value hierarchy. See “Note 3—Acquisitions and divestitures” for additional information regarding our acquisitions.
	Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2013 and 2012 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 6.60% and 7.10%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During 2013 and 2012, additions to our asset retirement obligations were $2,313 and $1,079, respectively. See “Note 8—Asset retirement obligations” for additional information regarding our asset retirement obligations.
	Impairment of long-lived assets. During the fourth quarter of 2012, we finalized a plan to dispose of three of our owned drilling rigs by sale that we no longer intended to utilize in oil and natural gas production. The estimated fair value related to the impairment assessment for our three drilling rigs no longer in service was primarily based on broker opinion and, therefore, is classified within Level 3 of the fair value hierarchy. During the years ended December 31, 2013 and 2012, we recognized impairment losses of $3,490 and $2,000, respectively, related to our three drilling rigs no longer in service and drill pipe based on broker opinion.
	Fair value of other financial instruments
	Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.
	The carrying value and estimated fair value of our long-term debt at December 31, 2013 and 2012 were as follows:
			December 31, 2013								December 31, 2012
	Level 2		Carrying				Estimated				Carrying				Estimated
			value				fair value				value				fair value
	9.875% Senior Notes due 2020		$	294,556			$	340,140			$	294,031			$	341,250
	8.25% Senior Notes due 2021		400,000				437,000				400,000				434,000
	7.625% Senior Notes due 2022		555,719				583,275				556,631				574,750
	Senior secured revolving credit facility		272,000				272,000				25,000				25,000
	Other secured long-term debt		16,437				16,437				17,740				17,740
			$	1,538,712			$	1,648,852			$	1,293,402			$	1,392,740
	The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our senior secured revolving credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.
	See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements.
	Concentrations of credit risk
	Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our senior secured revolving credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against current amounts owed to such counterparty lender under our senior secured revolving credit facility. As of December 31, 2013, the counterparties to our open derivative contracts consisted of twelve financial institutions, of which eleven were subject to our rights of offset under our senior secured revolving credit facility.
	The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.
			Offset in the consolidated balance sheets												Gross amounts not offset in the consolidated balance sheets
			Gross assets (liabilities)				Offsetting assets (liabilities)				Net assets (liabilities)				Amounts outstanding under senior secured revolving credit facility				Net amount
	As of December 31, 2013
	Derivative assets		$	13,113			$	(8,042	)		$	5,071			$	(4,211	)		$	860
	Derivative liabilities		(12,792		)		8,042				(4,750		)		—				(4,750		)
			$	321			$	—			$	321			$	(4,211	)		$	(3,890	)
	As of December 31, 2012
	Derivative assets		$	46,010			$	(4,721	)		$	41,289			$	(9,180	)		$	32,109
	Derivative liabilities		(5,605		)		4,721				(884		)		—				(884		)
			$	40,405			$	—			$	40,405			$	(9,180	)		$	31,225
	We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $12,792 at December 31, 2013.
	Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.
	Commodity sales to two purchasers accounted for 20.1% and 19.1% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2013. Commodity sales to three purchasers accounted for 19.6%, 13.9%, and 12.7% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2012. Commodity sales to three purchasers accounted for 15.1% and 13.6%, and 10.4% of total commodity sales, excluding the effects of hedging activities, during the year ended December 31, 2011. If we were to lose a purchaser, we believe we could replace it with a substitute purchaser.

Asset_retirement_obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset retirement obligations	'
	Asset retirement obligations
	The following table presents the balance and activity of our asset retirement obligations for the years ended December 31, 2013 and 2012.
		For the year ended December 31,
		2013			2012
	Beginning balance	$	49,214		$	46,493
	Liabilities incurred and assumed in current period	2,313			1,079
	Revisions in estimated cash flows	6,723			—
	Liabilities settled or disposed in current period	(7,016		)	(2,303		)
	Accretion	3,945			3,945
		55,179			49,214
	Less current portion	1,874			2,900
		$	53,305		$	46,314
	Liabilities incurred and assumed includes obligations related to new wells drilled and wells acquired during the period. Liabilities settled or disposed for the year ended December 31, 2013 increased significantly primarily due to the divestiture of certain non-strategic oil and natural gas properties sold during 2013 combined with increased plugging and abandoning activity. The revisions in the 2013 estimates are primarily due to increases in plugging and abandonment cost estimates based in part on actual costs incurred on recently plugged wells.
	We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,586 and $1,631 at December 31, 2013 and 2012, respectively, and is included in “Other assets” in our consolidated balance sheets. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.
	See “Note 7—Fair value measurements” for additional information regarding fair value measurements.

Income_taxes

Income taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income taxes	'
	Income taxes
	Income tax expense consists of the following for the years ended December 31:
		2013				2012				2011
	Current tax expense
	Federal tax benefit	$	(29	)		$	(23	)		$	(21	)
	State tax expense	1,144				141				200
	Current tax expense	1,115				118				179
	Deferred tax expense
	Federal tax expense	30,327				35,579				27,290
	State tax expense	1,407				2,140				8,455
	Deferred tax expense	31,734				37,719				35,745
		$	32,849			$	37,837			$	35,924
	Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:
		2013			2012			2011
	Statutory rate	35	%		35	%		35	%
	State income taxes, net of federal benefit	3.8	%		2.1	%		3.6	%
	Statutory depletion	(0.7	)%		(0.04	)%		(0.5	)%
	Valuation allowance	(1.7	)%		—	%		7.3	%
	Other	0.7	%		(0.04	)%		0.7	%
	Effective tax rate	37.1	%		37	%		46.1	%
	Components of the deferred tax assets and liabilities are as follows at December 31:
		2013				2012
	Deferred tax assets related to
	Asset retirement obligations	$	8,777			$	8,496
	Accrued expenses, allowance and other	14,508				10,129
	Derivative instruments	129				—
	Net operating loss carryforwards
	Federal	124,855				153,709
	State	13,350				16,339
	Statutory depletion carryforwards	2,867				2,242
	Alternative minimum tax credit carryforwards	308				308
		164,794				191,223
	Less valuation allowance	(10,385		)		(11,858		)
	Deferred tax asset	154,409				179,365
	Deferred tax liabilities related to
	Derivative instruments	—				(32,438		)
	Property and equipment	(206,799		)		(181,489		)
	Inventories	(1,205		)		(1,211		)
	Deferred tax liability	(208,004		)		(215,138		)
	Net deferred tax liability	(53,595		)		(35,773		)
	Less net current deferred tax asset (liability)	9,260				(26,872		)
	Long-term deferred tax liability	$	(62,855	)		$	(8,901	)
	Approximately $2,252 and $(33,066) of the current deferred tax asset (liability) at December 31, 2013 and 2012, respectively, relates to our short-term derivative instruments. Additionally, the current deferred tax asset (liability) includes an asset of approximately $656 and $1,015 related to asset retirement obligations at December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, taxes receivable of $434 and $245, respectively, are included in accounts receivable.
	We have federal net operating loss carryforwards of approximately $357,000 at December 31, 2013, which will expire between 2027 and 2033 if unused. At December 31, 2013, we have state net operating loss carryforwards of approximately $335,000, which will expire between 2014 and 2031 if unused. In addition, at December 31, 2013 we had federal percentage depletion carryforwards of approximately $8,000, which are not subject to expiration.
	At December 31, 2013, approximately $262,000 of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized. The decrease in the valuation allowance on the deferred tax asset of $1,473 during the year ended December 31, 2013 relates to utilization of our estimated state net operating loss carryforwards on the 2012 tax return and to adjustments to our expected realization of such carryforwards.
	Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that our deferred tax assets will be realized. The amount of our deferred tax assets considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

Stockbased_compensation

Stock-based compensation	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Stock-based compensation	'
	Stock-based compensation
	Phantom Stock Plan and Restricted Stock Unit Plan
	Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.
	Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.
	Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.
	A summary of our phantom stock and RSU activity during the three years ended December 31, 2013 is presented in the following table:
			Phantom Plan											RSU Plan
			Weighted				Phantom			Vest				Weighted			Restricted Stock Units			Vest
			average				shares			date				average						date
			grant date							fair				grant date						fair
			fair value							value				fair value						value
			(per share)											(per share)
	Unvested and outstanding at January 1, 2011		$	16.04			126,859							$	—		—
	Granted		$	18.55			37,316							$	—		—
	Vested		$	17.91			(17,064	)		$	309			$	—		—
	Forfeited		$	16.98			(21,343	)						$	—		—
	Unvested and outstanding at December 31, 2011		$	16.37			125,768							$	—		—
	Granted		$	—			—							$	17.07		177,026
	Vested		$	14.38			(26,908	)		$	431			$	—		—			$	—
	Forfeited		$	17.18			(14,096	)						$	16.8		(25,117	)
	Unvested and outstanding at December 31, 2012		$	16.87			84,764							$	17.12		151,909
	Granted		$	—			—							$	12.45		291,253
	Vested		$	16.2			(21,260	)		$	273			$	17.12		(50,246	)		$	626
	Forfeited		$	17.57			(10,342	)						$	14.27		(67,619	)
	Unvested and outstanding at December 31, 2013		$	17.01			53,162							$	13.53		325,297
	Based on an estimated fair value of $8.11 per phantom share and RSU as of December 31, 2013, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $3,069.
	2010 Equity Incentive Plan
	We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.
	The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards). The Time Vested awards vest in equal annual installments over the five-year vesting period , but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.
	Effective June 28, 2011, our board of directors modified the terms of the Time Vested awards to allow all participants in the 2010 Plan to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. This modification changed the classification of the Time Vested awards from equity to liability awards and resulted in a reclassification from additional paid-in capital to stock-based compensation liabilities of $2,640. These awards are remeasured to fair value at the end of each reporting period. Because the modification did not affect the fair value of the awards or the number of awards expected to vest, no incremental compensation cost was recorded as a result of the modification.
	Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares outstanding and to any new grants of Performance Vested shares were set at the following levels:
	Return on investment target				Shares vested
	175	%	per share		20	%	of shares multiplied by the Vesting Fraction
	200	%	per share		20	%	of shares multiplied by the Vesting Fraction
	250	%	per share		20	%	of shares multiplied by the Vesting Fraction
	300	%	per share		20	%	of shares multiplied by the Vesting Fraction
	350	%	per share		20	%	of shares multiplied by the Vesting Fraction
	This modification changed the classification of the canceled and reissued awards from equity to liability instruments and resulted in estimated incremental compensation cost of $4,322, which will be recognized over the five-year requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and will be adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited.
	A combined income and market valuation methodology was used to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2013, 2012, and 2011 was considered to be equal to the estimated fair value of our common equity per share, net of a discount for lack of control of 0%, 23%, and 23% and a discount for lack of marketability of 17%, 22%, and 20%, respectively. A control discount was not applied in 2013 pursuant to guidance released by the AICPA in 2013 that discourages incorporating  a control premium in the enterprise value used in valuing minority interest securities within an enterprise, except to the extent that such a premium reflects improvements to the business that a market participant would expect under current ownership.
	The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:
			2013							2012						2011
	Risk free interest rate		0.16	%	to	2.46		%		0.25	%	to	1.21		%	0.29	%	to	3.04		%
	Expected volatility		38	%	to	39		%		42	%	to	50		%				45		%
	Expected life					5 years							6 years						7 years
	Expected dividends					$	—						$	—					$	—
	Our expected volatility was calculated based on the average of the historical stock price volatility and the volatility implicit in the prices of the options or other traded financial instruments of our peer group. Our peer group consisted of the following oil and natural gas exploration and production companies in 2013: Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Pioneer Natural Resources Co., Resolute Energy Corporation, Sandridge Energy, Inc., and Whiting Petroleum Corp. Our peer group in 2012 consisted of Berry Petroleum Co., Concho Resources, Inc., Continental Resources, Inc., Denbury Resources, Inc., Laredo Petroleum Holdings, Inc., Pioneer Natural Resources Co., Sandridge Energy, Inc., and Whiting Petroleum Corp. Our peer group in 2011 included Encore Energy Partners, LP, and Venoco, Inc. in addition to the companies included in our 2012 peer group.
	A summary of our Time and Performance award activity during the three years ended December 31, 2013 is presented in the following table:
		Time Vested											Performance Vested
		Weighted				Restricted			Vest				Weighted			Restricted
		average				shares			date				average			shares
		grant date							fair				grant date
		fair value							value				fair value
		($ per share)											($ per share)
	Unvested and outstanding at January 1, 2011	$	684.15			10,049							$	295.1		41,297
	Granted	$	674.33			4,030							$	307		13,612
	Vested	$	684.15			(2,010	)		$	1,351			$	—		—
	Forfeited	$	684.15			(484	)						$	295.1		(1,811	)
	Unvested and outstanding at December 31, 2011	$	680.74			11,585							$	298.15		53,098
	Granted	$	572.7			2,444							$	394		15,050
	Vested	$	681.41			(2,673	)		$	1,980			$	—		—
	Forfeited	$	684.43			(1,875	)						$	295.96		(12,324	)
	Unvested and outstanding at December 31, 2012	$	651.97			9,481							$	298.15		55,824
	Granted	$	626.02			2,839							$	181.59		5,217
Vested	$	662.55			(2,509	)		$	1,556			$	—		—
Forfeited	$	618.87			(1,734	)						$	340.23		(3,171	)
Modified	$	626			11,169							$	324.47		(11,169	)
Unvested and outstanding at December 31, 2013	$	634.67			19,246							$	307.45		46,701
During 2013, 2012, and 2011, respectively, we repurchased and canceled 1,025, 1,469, and 528 vested shares, primarily for tax withholding, and we expect to repurchase approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $818.50 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $15,753 as of December 31, 2013.
Stock-based compensation cost
A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31:
		2013				2012				2011
Stock-based compensation cost		$	7,819			$	4,982			$	6,042
Less: stock-based compensation cost capitalized		(2,345		)		(1,917		)		(2,295		)
Stock-based compensation expense		$	5,474			$	3,065			$	3,747
Recognized tax benefit associated with stock-based compensation		$	2,031			$	1,230			$	1,547
Payments for stock-based compensation were $1,533, $1,386, and $661 during 2013, 2012, and 2011, respectively. As of December 31, 2013 and 2012, accrued payroll and benefits payable included $5,080 and $2,636, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $15,867 is expected to be recognized over a weighted-average period of 2.9 years.

Stockholders_equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Stockholders' equity	'
	Stockholders’ equity
	Common Stock
	Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to each of our existing stockholders.
	On January 13, 2014, CHK Energy Holdings Inc. (“CHK Energy Holdings”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The 279,999 class D shares and one class G share owned by CHK Energy Holdings automatically converted to class A common stock and all associated rights with the class D and class G common stock were terminated.
	All remaining shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”).
	Holders of class B and C common stock have the right, in aggregate, to designate three directors. Holders of class E common stock have the right to designate two directors.
	The class B, E, F and G common stock carry the following additional voting and consent rights:
	•	So long as the class B holders own 80% or more of the common stock they owned as of April 12, 2010, the closing date of our initial Stockholders Agreement (the “Original Date”), and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Original Date.
	•	In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock.
	•	Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO.
	•	Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO.
	The rights and preferences of a holder of class B, C, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.
	Stockholders Agreement
	Effective April 12, 2010, we implemented a Stockholders Agreement to provide for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our Senior Notes. The Stockholders Agreement was amended and restated on January 12, 2014 in conjunction with the sale of Chesapeake’s ownership interest in us to Healthcare of Ontario Pension Plan Trust Fund.
	Our Stockholders Agreement, as amended, also provides for the following stockholder-specific rights or restrictions:
	•	Prior to a Qualified IPO, Altoma Energy GP (“Altoma”) will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer Investments, L.L.C. (“Fischer”) votes for such approval.
	•	Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock.
	•	CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).
	•	Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.
	•	Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.
	•	Either (i) CCMP or (ii ) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met.
	•	At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO.
	•	At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer.
	With the exception of registration rights, the rights and preferences of a stockholder under the amended and restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

Related_party_transactions

Related party transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related party transactions	'
	Related party transactions
	Transactions with Chesapeake Energy Corporation
	CHK Energy Holdings owned approximately 20% of our outstanding common stock as of December 31, 2013. We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:
		Year ended December 31,
		2013			2012			2011
	Revenues	$	7,428		$	3,625		$	5,028
	Joint interest billings	$	(2,238	)	$	(4,896	)	$	(1,764	)
	In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:
		Year ended December 31,
		2013			2012			2011
	Revenues	$	(5,075	)	$	(4,084	)	$	(2,834	)
	Joint interest billings	$	9,689		$	9,785		$	4,056
	Amounts receivable from and payable to Chesapeake were as follows:
		As of December 31,
		2013			2012
	Receivable from Chesapeake	$	466		$	2,071
	Payable to Chesapeake	$	64		$	864
	On January 13, 2014, CHK Energy Holdings sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The sale by Chesapeake was in compliance with terms and conditions of the Stockholders Agreement described in “Note 11—Stockholders’ equity.”

Retirement_benefits

Retirement benefits	12 Months Ended
	Dec. 31, 2013
Disclosure Retirement Benefits Additional Information [Abstract]	'
Retirement benefits	'
	Retirement benefits
	We provide a 401(k) retirement plan for all employees, and during 2013, we matched employee contributions 100%, up to 7% of each employee’s gross wages, an increase from 6% and 6% during 2012 and 2011, respectively. At December 31, 2013, 2012, and 2011, there were 585, 661, and 625 employees, respectively, participating in the plan. Our contribution expense was $3,621, $2,809, and $2,390 for the years ended December 31, 2013, 2012 and 2011, respectively.

Commitments_and_contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and contingencies	'
	Commitments and contingencies
	Letters of Credit. Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 and $920 as of December 31, 2013 and 2012, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2013, 2012, or 2011.
	Commitments. We have four long-term contracts with four different suppliers to purchase CO2. Contract terms range from 2 to 20 years and provide for renewal or cancellation upon the occurrence of specific future events. Pricing under one of these contracts is fixed. Pricing under two of the contracts varies with the price of oil. The fourth contract provides fixed pricing through 2018 but becomes dependent upon the price of oil in subsequent years. Under this contract, we are obligated to purchase an average of approximately 24 MMcf/d in the first contract year and 35 MMcf/d for the remaining contract term or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate with six months’ notice.
	As of December 31, 2013, we were purchasing approximately 73 MMcf/d of CO2, from all sources combined and we expect to purchase an average of approximately 72 MMcf/d over the remaining contract terms. Purchases under these contracts were $3,849, $3,860, and $5,011 during 2013, 2012, and 2011, respectively.
	Based on current prices, our estimated minimum purchase obligations under our CO2 contracts are as follows:
	2014	$	2,506
	2015	2,552
	2016	1,289
	2017	1,289
	2018	2,008
	2019 and thereafter	10,186
		$	19,830
	Operating Leases. We rent equipment used on our oil and natural gas properties and have operating lease agreements for office equipment. Rent expense for the years ended December 31, 2013, 2012, and 2011 was $8,967, $8,144, and $6,715, respectively. Our leases relating to office equipment have terms of up to five years. As of December 31, 2013, total remaining payments associated with these operating leases were $955. We entered into two short-term interim agreements in 2013 for three compressors under construction. Completion and acceptance is expected to occur in 2014, at which time we will finalize operating lease terms.
	Other Contingencies. We have entered into change of control severance agreements under which our officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a period of months as calculated under the terms of the agreement and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to their termination date, plus (B) the officer’s bonus for the full year in which the termination date occurred.
	Litigation and Claims
	Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us in the United States District Court for the Western District of Oklahoma, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5,000. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Plaintiff’s Motion for Class Certification is due August 10, 2014. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.
	Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us in the District Court of Mayes County, Oklahoma, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
	In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

Oil_and_natural_gas_activities

Oil and natural gas activities	12 Months Ended
	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]	'
Oil and natural gas activities	'
	Oil and natural gas activities
	Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31:
			2013		2012		2011
	Property acquisition costs
	Proved properties		$	69,962	$	1,108	$	1,024
	Unproved properties		145,853		46,895		15,795
	Total acquisition costs		215,815		48,003		16,819
	Development costs		376,394		409,429		250,182
	Exploration costs(1)		77,507		54,432		57,016
	Total		$	669,716	$	511,864	$	324,017
	________________
	-1	Includes $37,344, $52,188, and $33,030 of EOR costs in 2013, 2012, and 2011, respectively.
	Depreciation, depletion, and amortization expense of oil and natural gas properties was $179,734, $154,788, and $132,307 for the years ended December 31, 2013, 2012, and 2011, respectively. The average depreciation, depletion and amortization rate per equivalent unit of production was $18.45, $16.98, and $15.29 for the years ended December 31, 2013, 2012, and 2011, respectively.
	Oil and natural gas properties not subject to amortization consist of the cost of unevaluated properties and seismic costs associated with specific unevaluated properties. Of the $321,477 of unproved property costs at 2013 being excluded from the amortization base, $169,044, $114,406, and $9,372 were incurred in 2013, 2012, and 2011, respectively, and $28,655 was incurred in prior years. We expect to complete our evaluation for the majority of these costs relating to non-EOR properties within the next two to five years.

Disclosures_about_oil_and_natu

Disclosures about oil and natural gas activities (unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Disclosures about oil and natural gas activities (unaudited)	'
	Disclosures about oil and natural gas activities (unaudited)
	The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.
	Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2013 are as follows:
			Oil			Natural Gas			Total
			(MBbls)(1)			(MMcf)			(MBoe)
	Proved developed and undeveloped reserves
	Balance at January 1, 2011		93,412			335,220			149,282
	Purchase of minerals in place		241			822			378
	Sales of minerals in place		(2,355	)		(7,134	)		(3,544	)
	Extensions and discoveries		6,362			40,896			13,178
	Revisions		6,711			(12,882	)		4,564
	Improved recoveries		1,057			—			1,057
	Production		(5,048	)		(21,642	)		(8,655	)
	Balance at December 31, 2011		100,380			335,280			156,260
	Purchase of minerals in place		—			57			9
	Sales of minerals in place		(2,694	)		(6,608	)		(3,795	)
	Extensions and discoveries		7,117			37,256			13,326
	Revisions		3,410			(89,036	)		(11,429	)
	Improved recoveries		842			—			842
	Production		(5,812	)		(19,834	)		(9,118	)
	Balance at December 31, 2012		103,243			257,115			146,095
	Proved developed reserves:
	1-Jan-11		55,607			257,754			98,566
	31-Dec-11		62,450			226,008			100,118
	31-Dec-12		63,956			185,826			94,927
	Proved undeveloped reserves:
	1-Jan-11		37,805			77,466			50,716
	31-Dec-11		37,930			109,272			56,142
	31-Dec-12		39,287			71,289			51,169
	________________
	-1	Includes natural gas liquids.
			Oil			Natural gas (MMcf)			Natural Gas Liquids			Total
			(MBbls)						(MBbls)			(MBoe)
	Proved developed and undeveloped reserves
	As of January 1, 2013		92,047			257,115			11,195			146,095
	Purchase of minerals in place		3,283			3,618			1,059			4,945
	Sales of minerals in place		(5,174	)		(9,708	)		(324	)		(7,116	)
	Extensions and discoveries		11,556			62,412			3,127			25,085
	Revisions(1)		(7,772	)		9,735			1,479			(4,671	)
	Improved recoveries		3,879			—			—			3,879
	Production		(5,006	)		(20,250	)		(1,361	)		(9,742	)
	Balance at December 31, 2013		92,813			302,922			15,175			158,475
	Proved developed reserves at December 31, 2013		56,360			196,920			11,484			100,664
	Proved undeveloped reserves at December 31, 2013		36,453			106,002			3,691			57,811
	________________
	-1	The downward revision in our oil reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and to negative technical revisions. These downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.
	The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.
	We believe that, in reviewing the information that follows, the following factors should be taken into account:
	•	future costs and sales prices will probably differ from those required to be used in these calculations;
	•	actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;
	•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and
	•	future net revenues may be subject to different rates of income taxation.
	Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 6—Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.
	In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			For the year ended December 31,
			2013				2012				2011
	Future cash flows		$	10,660,532			$	9,690,171			$	10,737,829
	Future production costs		(3,841,723		)		(3,737,069		)		(4,061,713		)
	Future development and abandonment costs		(1,506,585		)		(1,172,786		)		(1,202,438		)
	Future income tax provisions		(1,328,925		)		(1,223,036		)		(1,653,666		)
	Net future cash flows		3,983,299				3,557,280				3,820,012
	Less effect of 10% discount factor		(2,239,527		)		(2,033,599		)		(2,222,100		)
Standardized measure of discounted future net cash flows		$	1,743,772			$	1,523,681			$	1,597,912
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
		For the year ended December 31,
		2013				2012				2011
Beginning of year		$	1,523,681			$	1,597,912			$	1,236,026
Sale of oil and natural gas produced, net of production costs		(418,224		)		(346,627		)		(374,300		)
Net changes in prices and production costs		172,975				(206,640		)		538,466
Extensions and discoveries		514,743				224,903				224,027
Improved recoveries		79,589				14,204				17,969
Changes in future development costs		(236,121		)		(18,184		)		(238,881		)
Development costs incurred during the period that reduced future development costs		110,354				118,502				166,161
Revisions of previous quantity estimates		(95,855		)		(192,894		)		77,588
Purchases and sales of reserves in place, net		(20,021		)		(54,070		)		(40,662		)
Accretion of discount		152,830				214,794				169,679
Net change in income taxes		(60,981		)		166,238				(177,142		)
Changes in production rates and other		20,802				5,543				(1,019		)
End of year		$	1,743,772			$	1,523,681			$	1,597,912
The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.
		2013				2012				2011
Oil (per Bbl)		$	96.78			$	94.71			$	96.19
Natural gas (per Mcf)		$	3.67			$	2.76			$	4.11
Natural gas liquids (per Bbl) (1)		$	32.53			$	—			$	—
________________
-1	The NGL price is provided only for 2013 to coincide with our separate presentation of NGL reserves in that year.

Nature_of_operations_and_summa1

Nature of operations and summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Nature of operations	'
	Nature of operations and summary of significant accounting policies
	Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, and Kansas.
Principles of consolidation	'
	Principles of consolidation
	The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of estimates	'
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“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.
	The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; assigning fair value and allocating purchase price in connection with business combinations; valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.
Reclassifications	'
	Reclassifications
	Certain reclassifications have been made to prior period financial statements to conform to current period presentation.
Cash and cash equivalents	'
	Cash and cash equivalents
	We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts receivable	'
	Accounts receivable
	We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.
	We write off accounts receivable when they are determined to be uncollectible.
Inventories	'
	Inventories
	Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market.
Property and equipment	'
	Property and equipment
	Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently.
	Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method.
Oil and natural gas properties	'
	Oil and natural gas properties
	Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, capitalized interest on qualified projects and other internal costs directly attributable to these activities.
	The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work in progress costs are included in unevaluated oil and natural gas properties and as of December 31, 2013, include $196,227 of capital costs incurred for undeveloped acreage, $115,828 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination. As of December 31, 2012, work in progress costs included $64,840 of capital costs incurred for undeveloped acreage, $84,183 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $13,898 for wells and facilities in progress pending determination.
	Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
	Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), net of tax considerations, plus the cost of unproved properties not being amortized.
	Our estimates of oil and natural gas reserves as of December 31, 2013, 2012, and 2011 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). As of December 31, 2013, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $96.78 per Bbl of oil, $3.67 per Mcf of natural gas and $32.53 per Bbl of natural gas liquids for the year ended December 31, 2013.
	A decline in oil and natural gas prices subsequent to December 31, 2013 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
Assets held for sale and impairment of long-lived assets	'
	Assets held for sale
	Assets are classified as held for sale when the carrying amount will be recovered through a sale transaction rather than through continuing use. The classification is only made when we commit to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated, and measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and natural gas properties.
	In the fourth quarter of 2012, we finalized a plan to dispose of certain of our drilling rigs by sale. As a result of determining fair value less costs to sell on these assets, an impairment loss was recorded in the amount of $1,500 preceding classification as held for sale. In the third quarter of 2013, we reassessed the fair value of the drilling rigs classified as held for sale and recorded an additional impairment loss of $1,090.
	In late 2013, market conditions changed and hence the timing of the ultimate disposal of the drilling rigs became uncertain. Accordingly, we reclassified the drilling rigs to property and equipment in the consolidated balance sheets. The assets were measured at the lower of the carrying value of the assets before being classified as held for sale, adjusted for any depreciation that would have been recognized had the assets been continuously held and used, or the fair value of the assets at the date they no longer met the criteria as held for sale. As a result of this measurement, we recognized an additional loss of $2,400 in the fourth quarter of 2013. All impairment losses related to assets held for sale are included in loss on impairment of other assets in the consolidated statement of operations. We have reclassified our consolidated balance sheets as of December 31, 2012, to reflect the drilling rigs as assets held and used in order to conform to the current year presentation.
	Impairment of long-lived assets
	Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
	In addition to the impairments discussed above, during 2012, we recognized $500 of impairment losses primarily related to drill pipe held and used which was recorded in loss on impairment of other assets in the consolidated statements of operations.
Deferred income taxes	'
	Deferred income taxes
	Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.
	Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
	If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2013 and 2012, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.
	Tax years beginning with 1998 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
Derivative transactions	'
	Derivative transactions
	We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.
	Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and is reclassified into income as the hedged transactions occur. As of December 31, 2013, all amounts related to de-designated cash flow hedges have been reclassified into earnings.
	We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 6—Derivative instruments” for additional information regarding our derivative transactions.
Fair value measurements	'
	Fair value measurements
	Fair value is defined by the FASB 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. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
	Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
	Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 7—Fair value measurements” for additional information regarding our fair value measurements.
Valuation of business combinations	'
	Valuation of business combinations
	In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using a market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting.
Asset retirement obligations	'
	Asset retirement obligations
	We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells at the end of their productive lives and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 8—Asset retirement obligations” for additional information regarding our asset retirement obligations.
Environmental liabilities	'
	Environmental liabilities
	We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2013 and 2012, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.
Revenue recognition	'
	Revenue recognition
	Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products or services are recognized at the time of delivery of materials or performance of service.
Gas balancing	'
	Gas balancing
	In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production.
Stock-based compensation	'
	Stock-based compensation
	Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.
	The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.
	The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.
	We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.
	The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.
	The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.
	See “Note 10—Stock-based compensation” for additional information relating to stock-based compensation.
Recently adopted and issued accounting pronouncements	'
	Recently adopted accounting pronouncements
	Balance Sheet Offsetting. In December 2011, the FASB issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. In January 2013, additional guidance was issued which narrows the scope of the disclosure requirements to derivatives, securities borrowings, and securities lending transactions that are either offset or subject to a master netting arrangement. This guidance, which was effective and adopted by us in the first quarter of 2013, resulted in additional disclosures but had no financial impact.
	Presentation of Comprehensive Income. In February 2013, the FASB issued authoritative guidance that requires disclosures of the amounts reclassified out of AOCI by component, including the respective line items of net income if the amount is required to be reclassified to net income in its entirety in the same reporting period. This additional guidance was effective and adopted by us in the first quarter of 2013. As our entire balance in AOCI consists of deferred hedge gains, implementation of the guidance had no significant impact on our financial statement presentation and disclosures.
	Recently issued accounting pronouncements
	Other Expenses. In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We have assessed the impact that this fee and the adoption of the related authoritative guidance will have on our consolidated financial statements and determined the impact to be immaterial.

Nature_of_operations_and_summa2

Nature of operations and summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Components of Accounts Receivable	'
	Accounts receivable consisted of the following at December 31:
		2013			2012
	Joint interests	$	31,335		$	19,282
	Accrued commodity sales	60,768			50,814
	Derivative settlements	4,616			8,013
	Other	1,392			472
	Allowance for doubtful accounts	(1,596		)	(1,274		)
		$	96,515		$	77,307
Components of Inventories	'
	Inventories consisted of the following at December 31:
		2013			2012
	Equipment inventory	$	13,657		$	8,047
	Commodities	3,186			3,175
	Inventory valuation allowance	(706		)	(712		)
		$	16,137		$	10,510
Schedule Of Estimated Useful Lives for Property and Equipment	'
	Estimated useful lives of our assets are as follows:
	Furniture and fixtures			10 years
	Automobiles and trucks			5 years
	Machinery and equipment	10	—	20 years
	Office and computer equipment	5	—	10 years
	Building and improvements	10	—	40 years

Supplemental_disclosures_to_th1

Supplemental disclosures to the consolidated statements of cash flows (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]	'
Supplemental disclosures to the consolidated statements of cash flows	'
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year ended December 31,
		2013			2012			2011
	Net cash provided by operating activities included:
	Cash payments for interest	$	107,122		$	103,350		$	85,222
	Interest capitalized	(15,995		)	(4,437		)	(2,379		)
	Cash payments for interest, net of amounts capitalized	$	91,127		$	98,913		$	82,843
	Cash payments for income taxes	$	641		$	255		$	179
	Non-cash investing activities included:
	Asset retirement obligation additions and revisions	$	9,036		$	1,079		$	2,522
	Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities	$	27,875		$	24,280		$	(14,667	)
	Non-cash financing activities included:
	Modification of Time Vesting equity awards to liability plan	$	—		$	—		$	2,640

Acquisitions_and_divestitures_

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Purchase price allocation	'
	The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013. The purchase price allocation is preliminary and subject to adjustment upon the final closing settlement that we expect to complete during the second quarter of 2014.
	Consideration paid
	Cash, net of purchase price adjustments	$	153,858
	Fair value of identifiable assets acquired and liabilities assumed
	Oil and natural gas properties
	Proved	$	67,275
	Unevaluated	87,663
	Asset retirement obligations	(1,080		)
	Fair value of net identifiable assets acquired	$	153,858
Unaudited pro forma information	'
	The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects.
		Year ended December 31,
		2013			2012
	Revenues	$	690,564		$	599,344
	Operating expenses	$	448,751		$	402,677
	Net income	$	76,552		$	78,089

Property_and_equipment_Tables

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Components of Property and Equipment	'
	Major classes of property and equipment consist of the following at December 31:
		2013		2012
	Furniture and fixtures	$	2,405	$	2,327
	Automobiles and trucks	14,053		13,618
	Machinery and equipment	67,337		67,291
	Office and computer equipment	14,452		10,603
	Building and improvements	26,798		26,051
		125,045		119,890
	Less accumulated depreciation and amortization	64,350		55,356
		60,695		64,534
	Land	8,731		6,756
		$	69,426	$	71,290
Assets Held under Capital Leases	'
Components of Property and Equipment	'
	Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:
		2013		2012
	Office and computer equipment	$	1,926	$	1,926
	Machinery and equipment	642		642
		2,568		2,568
	Less accumulated depreciation and amortization	2,305		2,241
		$	263	$	327

Longterm_debt_Tables

Long-term debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Components of long-term debt	'
	As of the dates indicated, long-term debt consists of the following:
		December 31,
		2013		2012
	9.875% Senior Notes due 2020, net of discount of $5,444 and $5,969, respectively	$	294,556	$	294,031
	8.25% Senior Notes due 2021	400,000		400,000
	7.625% Senior Notes due 2022, including premium of $5,719 and $6,631, respectively	555,719		556,631
	Senior secured revolving credit facility	272,000		25,000
	Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property	11,202		12,596
	Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.87% to 6.79%, due January 2014 through February 2018; collateralized by automobiles, machinery and equipment	5,235		5,144
	Capital lease obligations	24,150		—
		1,562,862		1,293,402
	Less current maturities	5,334		3,746
		$	1,557,528	$	1,289,656
Maturities of long-term debt and capital leases, excluding premium or discount on our Senior Notes	'
	Maturities of long-term debt and capital leases, excluding premiums or discounts on our senior notes, are as follows as of December 31, 2013:
	2014	$	5,334
	2015	4,837
	2016	3,757
	2017	275,250
	2018	3,302
	2019 and thereafter	1,270,107
		$	1,562,587

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Outstanding derivative instruments	'
	The following table summarizes our crude oil derivatives outstanding as of December 31, 2013:
						Weighted average fixed price per Bbl
	Period and type of contract		Volume			Swaps				Sold puts				Purchased puts		Sold calls
			MBbls
	2014
	Swaps		961			$	93.5			$	—			$	—	$	—
	Three-way collars		2,400			$	—			$	75.5			$	93.25	$	101.94
	Enhanced swaps		840			$	98.62			$	80			$	—	$	—
	Put spread enhanced swaps		2,480			$	93.76			$	80			$	60	$	—
	Purchased puts		840			$	—			$	—			$	60	$	—
	2015
	Enhanced swaps		5,578			$	93.14			$	80			$	—	$	—
	The following tables summarize our natural gas derivative instruments outstanding as of December 31, 2013:
	Period and type of contract		Volume			Weighted
			BBtu			average
						fixed price
						per MMBtu
	2014
	Natural gas swaps		21,100			$	4.03
	Natural gas basis protection swaps		21,550			$	0.24
	2015
	Natural gas swaps		16,800			$	4.21
	Natural gas basis protection swaps		2,400			$	0.18
Derivative instruments recorded on the balance sheet at fair value	'
	The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.
		As of December 31, 2013												As of December 31, 2012
		Assets				Liabilities				Net value				Assets		Liabilities			Net value
	Natural gas swaps	$	1,457			$	(3,706	)		$	(2,249	)		$	13,642	$	(1,487	)	$	12,155
	Oil swaps	112				(2,807		)		(2,695		)		4,957		(1,339		)	3,618
	Oil collars	2,776				(4		)		2,772				27,411		(1,180		)	26,231
	Oil enhanced swaps	6,988				(6,212		)		776				—		—			—
	Oil purchased puts (1)	74				—				74				—		—			—
	Natural gas basis differential swaps	1,706				(63		)		1,643				—		(1,599		)	(1,599		)
	Total derivative instruments	13,113				(12,792		)		321				46,010		(5,605		)	40,405
	Less:
	Netting adjustments (2)	4,558				(4,558		)		—				2,977		(2,977		)	—
	Current portion asset (liability)	2,152				(8,234		)		(6,082		)		42,516		(436		)	42,080
		$	6,403			$	—			$	6,403			$	517	$	(2,192	)	$	(1,675	)
	___________
	-1	Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.
	-2	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
Derivative settlements outstanding	'
	Derivative settlements outstanding were as follows at December 31:
		2013				2012
	Derivative settlements receivable included in accounts receivable	$	4,616			$	8,013
	Derivative settlements payable included in accounts payable and accrued liabilities	$	377			$	41
Non-hedge derivative gains (losses) in the consolidated statements of operations	'
	Non-hedge derivative (losses) gains in the consolidated statements of operations are comprised of the following:
			2013				2012				2011
	Change in fair value of commodity price swaps		$	(20,717	)		$	(8,440	)		$	50,004
	Change in fair value of collars		(23,459		)		21,182				3,540
	Change in fair value of enhanced swaps and put options		186				—				—
	Change in fair value of natural gas basis differential contracts		3,242				(331		)		4,355
	Receipts from (payments on) settlement of commodity price swaps		5,122				28,716				(16,801		)
	Receipts from settlement of collars		14,548				10,229				1,250
	Payments on settlement of natural gas basis differential contracts		(557		)		(1,671		)		(7,940		)
			$	(21,635	)		$	49,685			$	34,408

Fair_value_measurements_Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair value hierarchy for financial assets and liabilities	'
	The fair value hierarchy for our financial assets and liabilities is shown by the following table:
		As of December 31, 2013												As of December 31, 2012
		Derivative				Derivative				Net assets				Derivative				Derivative				Net assets
		assets				liabilities				(liabilities)				assets				liabilities				(liabilities)
	Significant other observable inputs (Level 2)	$	3,275			$	(6,576	)		$	(3,301	)		$	18,599			$	(4,425	)		$	14,174
	Significant unobservable inputs (Level 3)	9,838				(6,216		)		3,622				27,411				(1,180		)		26,231
	Netting adjustments (1)	(4,558		)		4,558				—				(2,977		)		2,977				—
		$	8,555			$	(8,234	)		$	321			$	43,033			$	(2,628	)		$	40,405
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
Changes in the fair value of net commodity derivatives Classified as Level 3	'
	Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31 were:
	Net derivative assets		2013				2012
	Beginning balance		$	26,231			$	5,049
	Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains		(8,725		)		31,411
	Purchases		664				—
	Settlements received		(14,548		)		(10,229		)
	Ending balance		$	3,622			$	26,231
	Gains relating to instruments still held at the reporting date included in non-hedge derivative gains for the period		$	3,177			$	21,534
Fair value of other financial instruments	'
	The carrying value and estimated fair value of our long-term debt at December 31, 2013 and 2012 were as follows:
			December 31, 2013								December 31, 2012
	Level 2		Carrying				Estimated				Carrying				Estimated
			value				fair value				value				fair value
	9.875% Senior Notes due 2020		$	294,556			$	340,140			$	294,031			$	341,250
	8.25% Senior Notes due 2021		400,000				437,000				400,000				434,000
	7.625% Senior Notes due 2022		555,719				583,275				556,631				574,750
	Senior secured revolving credit facility		272,000				272,000				25,000				25,000
	Other secured long-term debt		16,437				16,437				17,740				17,740
			$	1,538,712			$	1,648,852			$	1,293,402			$	1,392,740
Offsetting Assets and Liabilities	'
	The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.
			Offset in the consolidated balance sheets												Gross amounts not offset in the consolidated balance sheets
			Gross assets (liabilities)				Offsetting assets (liabilities)				Net assets (liabilities)				Amounts outstanding under senior secured revolving credit facility				Net amount
	As of December 31, 2013
	Derivative assets		$	13,113			$	(8,042	)		$	5,071			$	(4,211	)		$	860
	Derivative liabilities		(12,792		)		8,042				(4,750		)		—				(4,750		)
			$	321			$	—			$	321			$	(4,211	)		$	(3,890	)
	As of December 31, 2012
	Derivative assets		$	46,010			$	(4,721	)		$	41,289			$	(9,180	)		$	32,109
	Derivative liabilities		(5,605		)		4,721				(884		)		—				(884		)
			$	40,405			$	—			$	40,405			$	(9,180	)		$	31,225

Asset_retirement_obligations_T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset retirement obligations	'
	The following table presents the balance and activity of our asset retirement obligations for the years ended December 31, 2013 and 2012.
		For the year ended December 31,
		2013			2012
	Beginning balance	$	49,214		$	46,493
	Liabilities incurred and assumed in current period	2,313			1,079
	Revisions in estimated cash flows	6,723			—
	Liabilities settled or disposed in current period	(7,016		)	(2,303		)
	Accretion	3,945			3,945
		55,179			49,214
	Less current portion	1,874			2,900
		$	53,305		$	46,314

Income_taxes_Tables

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Components of income tax expense	'
	Income tax expense consists of the following for the years ended December 31:
		2013				2012				2011
	Current tax expense
	Federal tax benefit	$	(29	)		$	(23	)		$	(21	)
	State tax expense	1,144				141				200
	Current tax expense	1,115				118				179
	Deferred tax expense
	Federal tax expense	30,327				35,579				27,290
	State tax expense	1,407				2,140				8,455
	Deferred tax expense	31,734				37,719				35,745
		$	32,849			$	37,837			$	35,924
Income tax rate reconciliation	'
	Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:
		2013			2012			2011
	Statutory rate	35	%		35	%		35	%
	State income taxes, net of federal benefit	3.8	%		2.1	%		3.6	%
	Statutory depletion	(0.7	)%		(0.04	)%		(0.5	)%
	Valuation allowance	(1.7	)%		—	%		7.3	%
	Other	0.7	%		(0.04	)%		0.7	%
	Effective tax rate	37.1	%		37	%		46.1	%
Components of deferred tax assets and liabilities	'
	Components of the deferred tax assets and liabilities are as follows at December 31:
		2013				2012
	Deferred tax assets related to
	Asset retirement obligations	$	8,777			$	8,496
	Accrued expenses, allowance and other	14,508				10,129
	Derivative instruments	129				—
	Net operating loss carryforwards
	Federal	124,855				153,709
	State	13,350				16,339
	Statutory depletion carryforwards	2,867				2,242
	Alternative minimum tax credit carryforwards	308				308
		164,794				191,223
	Less valuation allowance	(10,385		)		(11,858		)
	Deferred tax asset	154,409				179,365
	Deferred tax liabilities related to
	Derivative instruments	—				(32,438		)
	Property and equipment	(206,799		)		(181,489		)
	Inventories	(1,205		)		(1,211		)
	Deferred tax liability	(208,004		)		(215,138		)
	Net deferred tax liability	(53,595		)		(35,773		)
	Less net current deferred tax asset (liability)	9,260				(26,872		)
	Long-term deferred tax liability	$	(62,855	)		$	(8,901	)

Stockbased_compensation_Tables

Stock-based compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Return on investment targets for Performance Vested shares	'
	Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the return on investment targets applicable to the remaining number of Performance Vested shares outstanding and to any new grants of Performance Vested shares were set at the following levels:
	Return on investment target				Shares vested
	175	%	per share		20	%	of shares multiplied by the Vesting Fraction
	200	%	per share		20	%	of shares multiplied by the Vesting Fraction
	250	%	per share		20	%	of shares multiplied by the Vesting Fraction
	300	%	per share		20	%	of shares multiplied by the Vesting Fraction
	350	%	per share		20	%	of shares multiplied by the Vesting Fraction
Assumptions used in valuation of Performance Vested awards	'
	The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:
			2013							2012						2011
	Risk free interest rate		0.16	%	to	2.46		%		0.25	%	to	1.21		%	0.29	%	to	3.04		%
	Expected volatility		38	%	to	39		%		42	%	to	50		%				45		%
	Expected life					5 years							6 years						7 years
	Expected dividends					$	—						$	—					$	—
Stock-based compensation expense	'
	A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31:
			2013				2012				2011
	Stock-based compensation cost		$	7,819			$	4,982			$	6,042
	Less: stock-based compensation cost capitalized		(2,345		)		(1,917		)		(2,295		)
	Stock-based compensation expense		$	5,474			$	3,065			$	3,747
	Recognized tax benefit associated with stock-based compensation		$	2,031			$	1,230			$	1,547
Phantom Stock and RSU	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Rollforward of unvested stock-based compensation awards	'
	A summary of our phantom stock and RSU activity during the three years ended December 31, 2013 is presented in the following table:
			Phantom Plan											RSU Plan
			Weighted				Phantom			Vest				Weighted			Restricted Stock Units			Vest
			average				shares			date				average						date
			grant date							fair				grant date						fair
			fair value							value				fair value						value
			(per share)											(per share)
	Unvested and outstanding at January 1, 2011		$	16.04			126,859							$	—		—
	Granted		$	18.55			37,316							$	—		—
	Vested		$	17.91			(17,064	)		$	309			$	—		—
	Forfeited		$	16.98			(21,343	)						$	—		—
	Unvested and outstanding at December 31, 2011		$	16.37			125,768							$	—		—
	Granted		$	—			—							$	17.07		177,026
	Vested		$	14.38			(26,908	)		$	431			$	—		—			$	—
	Forfeited		$	17.18			(14,096	)						$	16.8		(25,117	)
	Unvested and outstanding at December 31, 2012		$	16.87			84,764							$	17.12		151,909
	Granted		$	—			—							$	12.45		291,253
	Vested		$	16.2			(21,260	)		$	273			$	17.12		(50,246	)		$	626
	Forfeited		$	17.57			(10,342	)						$	14.27		(67,619	)
	Unvested and outstanding at December 31, 2013		$	17.01			53,162							$	13.53		325,297
Restricted Stock	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Rollforward of unvested stock-based compensation awards	'
	A summary of our Time and Performance award activity during the three years ended December 31, 2013 is presented in the following table:
		Time Vested											Performance Vested
		Weighted				Restricted			Vest				Weighted			Restricted
		average				shares			date				average			shares
		grant date							fair				grant date
		fair value							value				fair value
		($ per share)											($ per share)
	Unvested and outstanding at January 1, 2011	$	684.15			10,049							$	295.1		41,297
	Granted	$	674.33			4,030							$	307		13,612
	Vested	$	684.15			(2,010	)		$	1,351			$	—		—
	Forfeited	$	684.15			(484	)						$	295.1		(1,811	)
	Unvested and outstanding at December 31, 2011	$	680.74			11,585							$	298.15		53,098
	Granted	$	572.7			2,444							$	394		15,050
	Vested	$	681.41			(2,673	)		$	1,980			$	—		—
	Forfeited	$	684.43			(1,875	)						$	295.96		(12,324	)
	Unvested and outstanding at December 31, 2012	$	651.97			9,481							$	298.15		55,824
	Granted	$	626.02			2,839							$	181.59		5,217
	Vested	$	662.55			(2,509	)		$	1,556			$	—		—
	Forfeited	$	618.87			(1,734	)						$	340.23		(3,171	)
	Modified	$	626			11,169							$	324.47		(11,169	)
	Unvested and outstanding at December 31, 2013	$	634.67			19,246							$	307.45		46,701

Related_party_transactions_Tab

Related party transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related party transactions	'
	We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:
		Year ended December 31,
		2013			2012			2011
	Revenues	$	7,428		$	3,625		$	5,028
	Joint interest billings	$	(2,238	)	$	(4,896	)	$	(1,764	)
	In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:
		Year ended December 31,
		2013			2012			2011
	Revenues	$	(5,075	)	$	(4,084	)	$	(2,834	)
	Joint interest billings	$	9,689		$	9,785		$	4,056
	Amounts receivable from and payable to Chesapeake were as follows:
		As of December 31,
		2013			2012
	Receivable from Chesapeake	$	466		$	2,071
	Payable to Chesapeake	$	64		$	864

Commitments_and_contingencies_

Commitments and contingencies Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Unrecorded Unconditional Purchase Obligations Disclosure	'
	Based on current prices, our estimated minimum purchase obligations under our CO2 contracts are as follows:
	2014	$	2,506
	2015	2,552
	2016	1,289
	2017	1,289
	2018	2,008
	2019 and thereafter	10,186
		$	19,830

Oil_and_natural_gas_activities1

Oil and natural gas activities (Tables)	12 Months Ended
	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract]	'
Cost incurred in oil and natural gas producing activities	'
	Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31:
			2013		2012		2011
	Property acquisition costs
	Proved properties		$	69,962	$	1,108	$	1,024
	Unproved properties		145,853		46,895		15,795
	Total acquisition costs		215,815		48,003		16,819
	Development costs		376,394		409,429		250,182
	Exploration costs(1)		77,507		54,432		57,016
	Total		$	669,716	$	511,864	$	324,017
	________________
	-1	Includes $37,344, $52,188, and $33,030 of EOR costs in 2013, 2012, and 2011, respectively.

Disclosures_about_oil_and_natu1

Disclosures about oil and natural gas activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Summary of changes in quantities of proved oil and natural gas reserves	'
	Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2013 are as follows:
			Oil			Natural Gas			Total
			(MBbls)(1)			(MMcf)			(MBoe)
	Proved developed and undeveloped reserves
	Balance at January 1, 2011		93,412			335,220			149,282
	Purchase of minerals in place		241			822			378
	Sales of minerals in place		(2,355	)		(7,134	)		(3,544	)
	Extensions and discoveries		6,362			40,896			13,178
	Revisions		6,711			(12,882	)		4,564
	Improved recoveries		1,057			—			1,057
	Production		(5,048	)		(21,642	)		(8,655	)
	Balance at December 31, 2011		100,380			335,280			156,260
	Purchase of minerals in place		—			57			9
	Sales of minerals in place		(2,694	)		(6,608	)		(3,795	)
	Extensions and discoveries		7,117			37,256			13,326
	Revisions		3,410			(89,036	)		(11,429	)
	Improved recoveries		842			—			842
	Production		(5,812	)		(19,834	)		(9,118	)
	Balance at December 31, 2012		103,243			257,115			146,095
	Proved developed reserves:
	1-Jan-11		55,607			257,754			98,566
	31-Dec-11		62,450			226,008			100,118
	31-Dec-12		63,956			185,826			94,927
	Proved undeveloped reserves:
	1-Jan-11		37,805			77,466			50,716
	31-Dec-11		37,930			109,272			56,142
	31-Dec-12		39,287			71,289			51,169
	________________
	-1	Includes natural gas liquids.
			Oil			Natural gas (MMcf)			Natural Gas Liquids			Total
			(MBbls)						(MBbls)			(MBoe)
	Proved developed and undeveloped reserves
	As of January 1, 2013		92,047			257,115			11,195			146,095
	Purchase of minerals in place		3,283			3,618			1,059			4,945
	Sales of minerals in place		(5,174	)		(9,708	)		(324	)		(7,116	)
	Extensions and discoveries		11,556			62,412			3,127			25,085
	Revisions(1)		(7,772	)		9,735			1,479			(4,671	)
	Improved recoveries		3,879			—			—			3,879
	Production		(5,006	)		(20,250	)		(1,361	)		(9,742	)
	Balance at December 31, 2013		92,813			302,922			15,175			158,475
	Proved developed reserves at December 31, 2013		56,360			196,920			11,484			100,664
	Proved undeveloped reserves at December 31, 2013		36,453			106,002			3,691			57,811
	________________
	-1	The downward revision in our oil reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and to negative technical revisions. These downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	'
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			For the year ended December 31,
			2013				2012				2011
	Future cash flows		$	10,660,532			$	9,690,171			$	10,737,829
	Future production costs		(3,841,723		)		(3,737,069		)		(4,061,713		)
	Future development and abandonment costs		(1,506,585		)		(1,172,786		)		(1,202,438		)
	Future income tax provisions		(1,328,925		)		(1,223,036		)		(1,653,666		)
	Net future cash flows		3,983,299				3,557,280				3,820,012
	Less effect of 10% discount factor		(2,239,527		)		(2,033,599		)		(2,222,100		)
	Standardized measure of discounted future net cash flows		$	1,743,772			$	1,523,681			$	1,597,912
Changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	'
	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
			For the year ended December 31,
			2013				2012				2011
	Beginning of year		$	1,523,681			$	1,597,912			$	1,236,026
	Sale of oil and natural gas produced, net of production costs		(418,224		)		(346,627		)		(374,300		)
	Net changes in prices and production costs		172,975				(206,640		)		538,466
	Extensions and discoveries		514,743				224,903				224,027
	Improved recoveries		79,589				14,204				17,969
	Changes in future development costs		(236,121		)		(18,184		)		(238,881		)
	Development costs incurred during the period that reduced future development costs		110,354				118,502				166,161
	Revisions of previous quantity estimates		(95,855		)		(192,894		)		77,588
	Purchases and sales of reserves in place, net		(20,021		)		(54,070		)		(40,662		)
	Accretion of discount		152,830				214,794				169,679
	Net change in income taxes		(60,981		)		166,238				(177,142		)
	Changes in production rates and other		20,802				5,543				(1,019		)
	End of year		$	1,743,772			$	1,523,681			$	1,597,912
Prices used in determining future net revenues related to standardized measure calculation	'
	The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.
			2013				2012				2011
	Oil (per Bbl)		$	96.78			$	94.71			$	96.19
	Natural gas (per Mcf)		$	3.67			$	2.76			$	4.11
	Natural gas liquids (per Bbl) (1)		$	32.53			$	—			$	—
	________________
	-1	The NGL price is provided only for 2013 to coincide with our separate presentation of NGL reserves in that year.

Recovered_Sheet1

Nature of Operations and Summary of Significant Accounting Policies--Additional Information (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

In Thousands, unless otherwise specified

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, 2012

Sep. 30, 2013

Dec. 31, 2013

Under Production [Member]

Under Production [Member]

Over Production [Member]

Over Production [Member]

Drilling rigs

Drilling rigs

Drill pipe

Assets held for sale

JP Morgan Chase Bank, N.A. [Member]

MMcf

MMcf

MMcf

MMcf

Drilling rigs

Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Cash held at JP Morgan Chase Bank, N.A.

'

'

'

'

'

'

'

'

'

'

'

$46,692

Loss on impairment of other assets

3,490

2,000

0

'

'

'

'

2,400

1,500

500

1,090

'

Gas balancing volume (in MMcf)

'

'

'

2,449

2,690

1,553

1,658

'

'

'

'

'

Gas balancing payable

$1,588

$1,984

'

'

'

'

'

'

'

'

'

'

Recovered_Sheet2

Nature of Operations and Summary of Significant Accounting Policies--Accounts Receivable (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Period within which joint interest accounts receivable are due	'30 days	'	'
Period within which joint interest accounts receivable are past due	'60 days	'	'
Bad debt expense	$498	$731	$179
Receivables [Abstract]	'	'	'
Joint interests	31,335	19,282	'
Accrued commodity sales	60,768	50,814	'
Derivative settlements	4,616	8,013	'
Other	1,392	472	'
Allowance for doubtful accounts	-1,596	-1,274	'
Accounts receivable, net	$96,515	$77,307	'

Recovered_Sheet3

Nature of Operations and Summary of Significant Accounting Policies--Inventories (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Inventory write-down	$0	$0	$602
Equipment inventory	13,657	8,047	'
Oil and natural gas product	3,186	3,175	'
Inventory valuation allowance	706	712	'
Inventories, net	$16,137	$10,510	'

Nature_of_Operations_and_Summa3

Nature of Operations and Summary of Significant Accounting Policies--Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2013
Furniture and fixtures	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'10 years
Automobiles and trucks	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'5 years
Machinery and equipment | Minimum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'10 years
Machinery and equipment | Maximum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'20 years
Office and computer equipment | Minimum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'5 years
Office and computer equipment | Maximum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'10 years
Building and improvements | Minimum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'10 years
Building and improvements | Maximum	'
Property, Plant and Equipment [Line Items]	'
Property and equipment, useful life	'40 years

Recovered_Sheet4

Nature of operations and summary of significant accounting policies Nature of Operations and Summary of Significant Accounting Policies--Oil and Natural Gas Properties (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'
Capital costs for undeveloped acreage	$196,227	$64,840
CO2 Delivery Pipelines and Facilities	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'
Exploration and development costs excluded from amortization	115,828	84,183
Wells and Facilities in Progress	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'
Exploration and development costs excluded from amortization	$9,422	$13,898

Nature_of_Operations_and_Summa4

Nature of Operations and Summary of Significant Accounting Policies--Average Prices (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Oil	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	96.78		'		'
Natural Gas	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	3.67		2.76		4.11
Natural Gas Liquids	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	32.53	[1]	0	[1]	0	[1]
[1]	The NGL price is provided only for 2013 to coincide with our separate presentation of NGL reserves in that year.

Recovered_Sheet5

Supplemental Disclosures to the Consolidated Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash provided by operating activities included:	'	'	'
Cash payments for interest	$107,122	$103,350	$85,222
Interest capitalized	-15,995	-4,437	-2,379
Cash payments for interest, net of amounts capitalized	91,127	98,913	82,843
Cash payments for income taxes	641	255	179
Non-cash investing activities included:	'	'	'
Asset retirement obligation additions and revisions	9,036	1,079	2,522
Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities	27,875	24,280	-14,667
Modification of Time Vesting equity awards to liability plan	$0	$0	$2,640

Recovered_Sheet6

Acquisitions and Divestitures (Detail) (USD $)	12 Months Ended					1 Months Ended	12 Months Ended		1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	30-May-12	Dec. 31, 2013	Dec. 31, 2012	Nov. 30, 2011	Nov. 30, 2011
				Creek, Love, and Carter Counties, Oklahoma	Texas County, Oklahoma	Southern Oklahoma	Cabot Oil & Gas Corporation	Cabot Oil & Gas Corporation	Charger Resources, LLC	Green Country Supply, Inc.
							Panhandle Marmaton Play	Panhandle Marmaton Play	Rocky Mountains
							acre
Cabot Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Payments to Acquire Businesses, Net of Cash Acquired	$153,858	$0	$0	'	'	'	$153,858	'	'	'
Oil and natural gas acres, gross	'	'	'	'	'	'	131,000	'	'	'
Oil and natural gas acres, net	'	'	'	'	'	'	66,000	'	'	'
Acquisition related costs	'	'	'	'	'	'	951	'	'	'
Purchase Price Allocation	'	'	'	'	'	'	'	'	'	'
Proved oil and natural gas properties	'	'	'	'	'	'	67,275	'	'	'
Unevaluated oil and natural gas properties	'	'	'	'	'	'	87,663	'	'	'
Asset retirement obligations	'	'	'	'	'	'	-1,080	'	'	'
Fair value of net identifiable assets acquired	'	'	'	'	'	'	153,858	'	'	'
Unaudited Pro Forma Information	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	690,564	599,344	'	'
Operating Expenses	'	'	'	'	'	'	448,751	402,677	'	'
Net income	'	'	'	'	'	'	76,552	78,089	'	'
Proceeds from sale of oil and gas properties	109,710	'	'	61,440	17,800	37,000	'	'	33,100	'
Proceeds from sale of other assets	'	'	'	'	'	'	'	'	'	4,433
Gain on sale of assets	$670	$149	$1,284	'	'	'	'	'	'	$2,630

Property_and_EquipmentComponen

Property and Equipment--Components of Property and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Components Of Property And Equipment [Abstract]	'	'
Furniture and fixtures	$2,405	$2,327
Automobiles and trucks	14,053	13,618
Machinery and equipment	67,337	67,291
Office and computer equipment	14,452	10,603
Building and improvements	26,798	26,051
Property and equipment, excluding land, gross	125,045	119,890
Less accumulated depreciation and amortization	64,350	55,356
Property and equipment, excluding land, net	60,695	64,534
Land	8,731	6,756
Property and equipment - at cost, net	$69,426	$71,290

Property_and_EquipmentSchedule

Property and Equipment--Schedule of Property and Equipment Leased Under Capital Leases (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property and equipment leased under capital leases, gross	$2,568	$2,568
Less accumulated depreciation and amortization	2,305	2,241
Property and equipment leased under capital leases, net	263	327
Office and computer equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Property and equipment leased under capital leases, gross	1,926	1,926
Machinery and equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Property and equipment leased under capital leases, gross	$642	$642

LongTerm_DebtComponents_of_Lon

Long-Term Debt--Components of Long-Term Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Long-term debt [Abstract]	'	'
Senior secured revolving credit facility	$272,000	$25,000
Real estate mortgage notes payable	11,202	12,596
Installment notes payable	5,235	5,144
Capital lease obligations	24,150	0
Total long-term debt and capital lease obligations	1,562,862	1,293,402
Less current maturities	5,334	3,746
Long-term debt and capital leases, less current maturities	1,557,528	1,289,656
9.875% Senior Notes due 2020	'	'
Long-term debt [Abstract]	'	'
Senior Notes	294,556	294,031
8.25% Senior Notes due 2021	'	'
Long-term debt [Abstract]	'	'
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022	'	'
Long-term debt [Abstract]	'	'
Senior Notes	$555,719	$556,631

LongTerm_DebtParenthetical_Det

Long-Term Debt--Parenthetical (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified	9.875% Senior Notes due 2020	9.875% Senior Notes due 2020	7.625% Senior Notes due 2022	7.625% Senior Notes due 2022	Mortgages	Mortgages	Secured Debt	Secured Debt
					Minimum	Maximum	Minimum	Maximum
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'
Stated interest rate	'	'	'	'	2.54%	5.46%	2.87%	6.79%
Maturity date	'	'	'	'	'2021-08	'2028-12	'2014-01	'2018-02
Unamortized discount on 9.875% Senior Notes due 2020	$5,444	$5,969	'	'	'	'	'	'
Unamortized premium on 7.625% Senior Notes due 2022	'	'	$5,719	$6,631	'	'	'	'

LongTerm_DebtMaturities_of_Lon

Long-Term Debt--Maturities of Long-Term Debt and Capital Leases (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Maturities of Long-term Debt [Abstract]	'
2014	$5,334
2015	4,837
2016	3,757
2017	275,250
2018	3,302
2019 and thereafter	1,270,107
Long-term debt and capital leases, excluding premium or discount on Senior Notes	$1,562,587

Longterm_debt_LongTerm_DebtSen

Long-term debt Long-Term Debt--Senior Notes (Details) (USD $)

12 Months Ended

12 Months Ended

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, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Feb. 22, 2011

Dec. 31, 2013

Nov. 15, 2012

2-May-12

Dec. 31, 2012

2-May-12

Dec. 31, 2011

Feb. 22, 2011

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

9.875% Senior Notes due 2020

8.25% Senior Notes due 2021

8.25% Senior Notes due 2021

7.625% Senior Notes due 2022

7.625% Senior Notes due 2022

7.625% Senior Notes due 2022

8.875% Senior Notes Due 2017

8.875% Senior Notes Due 2017

8.5% Senior Notes Due 2015

8.5% Senior Notes Due 2015

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Notes, stated interest rate

'

'

'

'

'

'

9.88%

8.25%

8.25%

7.63%

7.63%

7.63%

'

8.88%

'

8.50%

Maturity date (year)

'

'

'

'

'

'

'2020

'2021

'

'2022

'

'

'

'

'

'

Net amortization of (premium) discount

'

'

'

($387)

$439

$668

'

'

'

'

'

'

'

'

'

'

Redemption price at change of control event, as a percentage of principal

'

'

'

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount

'

'

'

'

'

'

'

'

400,000

'

150,000

400,000

'

'

'

'

Loss on extinguishment of debt

$0

($21,714)

($20,592)

'

'

'

'

'

'

'

'

'

($21,714)

'

($20,592)

'

Maturity date

'

'

'

'

'

'

'

1-Sep-21

'

15-Nov-22

'

'

'

'

'

'

LongTerm_DebtSenior_Secured_Re

Long-Term Debt--Senior Secured Revolving Credit Facility (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 29, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 29, 2013

Oct. 29, 2013

Oct. 29, 2013

In Thousands, unless otherwise specified

Eurodollar Rate Option

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Quarters

Election One

Election Two

Election Three

Minimum

Maximum

Maximum

Eurodollar Rate Option

Eurodollar Rate Option

Eurodollar Rate Option

Alternate Base Rate Option

Alternate Base Rate Option

Federal Funds Effective Rate

Adjusted LIBO Rate

Pre-Amendment

Post-Amendment

Post-Cabot Acquisition

Minimum

Maximum

Minimum

Maximum

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturity date

'

'

'

1-Nov-17

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing base amount

'

'

'

$600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

$500,000

$550,000

$600,000

Additional Permitted Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000

'

Derivatives permitted on properties to be acquired, as a percentage of anticipated PDP production

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

Permitted Other Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40,000

50,000

'

Credit facility balance subject to Eurodollar rate

$272,000

$25,000

$272,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

One month interest period

'

'

'

'

'

'

'

'

'

'

'1 month

'

'

'

'

'

'

'

'

'

Two month interest period

'

'

'

'

'

'

'

'

'

'

'2 months

'

'

'

'

'

'

'

'

'

Three month interest period

'

'

'

'

'

'

'

'

'

'

'3 months

'

'

'

'

'

'

'

'

'

Six month interest period

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

Basis spread on variable rate

'

'

'

'

'

'

'

'

'

'

'

1.50%

1.75%

0.50%

0.75%

0.50%

1.00%

'

'

'

Frequency of periodic interest payment on senior secured revolving credit facility

'

'

'

'

'

'

'

'

'

'

'

'3 months

'

'

'

'

'

'

'

'

Commitment fee on unused portion of the borrowing base

'

'

'

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

'

'

'

'

'

Current Ratio covenant

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

Ratio Of Consolidated Net Debt To Consolidated EBITDAX covenant

'

'

'

'

'

'

'

'

4.5

'

'

'

'

'

'

'

'

'

'

'

Number of consecutive quarters used in Consolidated Net Debt to Consolidated EBITDAX ratio calculation

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of days to make election to eliminate borrowings in excess of borrowing base as the result of a redetermination

'

'

'

'10 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination

'

'

'

'

'30 days

'30 days

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of time over which borrowings in excess of borrowing base can be repaid in equal monthly installments

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LongTerm_DebtDebt_Issuance_Cos

Long-Term Debt--Debt Issuance Costs and Capital Leases (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Issuance Costs [Abstract]	'	'	'
Amortization of debt issuance costs	$2,197	$1,694	$1,608
Capital Leases [Abstract]	'	'	'
Proceeds from sale leaseback	24,500	0	0
Capital Lease Obligations | U.S. Bank National Association	'	'	'
Capital Leases [Abstract]	'	'	'
Proceeds from sale leaseback	24,500	'	'
Lease term	'84 months	'	'
Purchase option period	'72 months	'	'
Implicit interest rate	3.80%	'	'
Minimum lease payments	3,181	'	'
Other Assets [Member]	'	'	'
Debt Issuance Costs [Abstract]	'	'	'
Unamortized debt issuance cost	$23,273	$25,410	'

Derivative_InstrumentsDerivati

Derivative Instruments--Derivatives Outstanding (Details)	Dec. 31, 2013
	bbl
Swaps | Derivatives Maturing In 2014 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	961,000
Weighted average fixed price per unit, swaps	93.5
Swaps | Derivatives Maturing In 2014 | Natural Gas Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	21,100,000
Weighted average fixed price per unit, swaps	4.03
Swaps | Derivatives maturing in 2015 | Natural Gas Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	16,800,000
Weighted average fixed price per unit, swaps	4.21
Costless Collars | Derivatives Maturing In 2014 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	2,400,000
Weighted average fixed price per Bbl, sold puts	75.5
Weighted average fixed price per Bbl, purchased puts	93.25
Weighted average fixed price per Bbl, sold calls	101.94
Enhanced Swap | Derivatives Maturing In 2014 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	840,000
Weighted average fixed price per unit, swaps	98.62
Weighted average fixed price per Bbl, sold puts	80
Enhanced Swap | Derivatives maturing in 2015 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	5,578,000
Weighted average fixed price per unit, swaps	93.14
Weighted average fixed price per Bbl, sold puts	80
Put Spread Enhanced Swap | Derivatives Maturing In 2014 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	2,480,000
Weighted average fixed price per unit, swaps	93.76
Weighted average fixed price per Bbl, sold puts	80
Weighted average fixed price per Bbl, purchased puts	60
Put Options Purchased | Derivatives Maturing In 2014 | Crude Oil Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	840,000
Weighted average fixed price per Bbl, purchased puts	60
Basis Protection Swaps | Derivatives Maturing In 2014 | Natural Gas Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	21,550,000
Weighted average fixed price per unit, swaps	0.24
Basis Protection Swaps | Derivatives maturing in 2015 | Natural Gas Derivative	'
Derivative [Line Items]	'
Volume of derivative instruments held	2,400,000
Weighted average fixed price per unit, swaps	0.18

Derivative_InstrumentsEstimate

Derivative Instruments--Estimated Fair Value of Derivative Instruments (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2013		Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	($13,113)		($46,010)
Current derivative assets, net	'	2,152		42,516
Long-term derivative assets, net	'	6,403		517
Derivative liabilities, gross	'	-12,792		-5,605
Current derivative liabilities, net	'	-8,234		-436
Long-term derivative liabilities, net	'	0		-2,192
Derivative assets (liabilities), net	'	321		40,405
Current derivative assets (liabilities), net	'	-6,082		42,080
Long-term derivative assets (liabilities), net	'	6,403		-1,675
Netting adjustments	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	4,558	[1]	2,977	[1]
Derivative liabilities, gross	'	4,558	[1]	2,977	[1]
Swaps | Crude Oil Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-112		-4,957
Derivative liabilities, gross	'	-2,807		-1,339
Derivative assets (liabilities), net	'	-2,695		3,618
Swaps | Natural Gas Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-1,457		-13,642
Derivative liabilities, gross	'	-3,706		-1,487
Derivative assets (liabilities), net	'	-2,249		12,155
Costless Collars | Crude Oil Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-2,776		-27,411
Derivative liabilities, gross	'	-4		-1,180
Derivative assets (liabilities), net	'	2,772		26,231
Enhanced Swap | Crude Oil Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-6,988		'
Derivative liabilities, gross	'	-6,212		'
Derivative assets (liabilities), net	'	776		0
Put Options Purchased | Crude Oil Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-74	[2]	'
Derivative liabilities, gross	'	0	[2]	'
Derivative assets (liabilities), net	'	74	[2]	0	[2]
Premium Paid For Put Options On Commodity Derivative Contracts	664	'		'
Basis Protection Swaps | Natural Gas Derivative	'	'		'
Derivatives, Fair Value [Line Items]	'	'		'
Derivative assets, gross	'	-1,706		0
Derivative liabilities, gross	'	-63		-1,599
Derivative assets (liabilities), net	'	$1,643		($1,599)
[1]	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
[2]	Includes premiums of $664 paid during the second quarter of 2013. No additional premiums have been paid.

Derivative_InstrumentsDerivati1

Derivative Instruments--Derivative Settlements Outstanding (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Derivative settlements receivable included in accounts receivable	$4,616	$8,013
Derivative settlements payable included in accounts payable and accrued liabilities	$377	$41

Derivative_InstrumentsNonHedge

Derivative Instruments--Non-Hedge Derivative Gains (Losses) in the Consolidated Statements of Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-Hedge Derivative Gains (Losses) [Line Items]	'	'	'
Non-hedge derivative (losses) gains	($21,635)	$49,685	$34,408
Swaps	'	'	'
Non-Hedge Derivative Gains (Losses) [Line Items]	'	'	'
Change in fair value of non-hedge derivatives	-20,717	-8,440	50,004
Receipts from (payments on) settlement of non-hedge derivative instruments	5,122	28,716	-16,801
Costless Collars	'	'	'
Non-Hedge Derivative Gains (Losses) [Line Items]	'	'	'
Change in fair value of non-hedge derivatives	-23,459	21,182	3,540
Receipts from (payments on) settlement of non-hedge derivative instruments	14,548	10,229	1,250
Enhanced Swaps and Put Options	'	'	'
Non-Hedge Derivative Gains (Losses) [Line Items]	'	'	'
Change in fair value of non-hedge derivatives	186	0	0
Basis Protection Swaps	'	'	'
Non-Hedge Derivative Gains (Losses) [Line Items]	'	'	'
Change in fair value of non-hedge derivatives	3,242	-331	4,355
Receipts from (payments on) settlement of non-hedge derivative instruments	($557)	($1,671)	($7,940)

Fair_Value_MeasurementsRecurri

Fair Value Measurements--Recurring Fair Value Measurements--Inputs (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'	'
Rate reflecting our nonperformance risk	1.75%	1.50%
Weighted-average rate reflecting our counterparties' nonperformance risk	0.31%	0.32%

Fair_Value_MeasurementsFair_Va

Fair Value Measurements--Fair Value Hierarchy (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets, gross	$13,113		$46,010
Derivative liabilities, gross	-12,792		-5,605
Derivative assets (liabilities), net	321		40,405
Netting adjustments	'		'
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets, gross	-4,558	[1]	-2,977	[1]
Derivative liabilities, gross	4,558	[1]	2,977	[1]
Recurring Fair Value Measurements	'		'
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets (liabilities), net	321		40,405
Derivative assets, net	8,555		43,033
Derivative liabilities, net	-8,234		-2,628
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)	'		'
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets, gross	3,275		18,599
Derivative liabilities, gross	-6,576		-4,425
Derivative assets (liabilities), net	-3,301		14,174
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)	'		'
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets, gross	9,838		27,411
Derivative liabilities, gross	-6,216		-1,180
Derivative assets (liabilities), net	3,622		26,231
Recurring Fair Value Measurements | Netting adjustments	'		'
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis [Line Items]	'		'
Derivative assets, gross	-4,558	[1]	-2,977	[1]
Derivative liabilities, gross	4,558	[1]	2,977	[1]
Derivative assets (liabilities), net	$0	[1]	$0	[1]
[1]	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

Fair_Value_MeasurementsChanges

Fair Value Measurements--Changes in Fair Value of Derivatives Classified as Level 3 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Level 3 Rollforward	'	'
Beginning balance	$26,231	$5,049
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	-8,725	31,411
Purchases	664	0
Settlements received	-14,548	-10,229
Ending balance	3,622	26,231
Significant unobservable inputs (Level 3) | Derivative	'	'
Level 3 Rollforward	'	'
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains for the period	$3,177	$21,534

Fair_Value_MeasurementsNonrecu

Fair Value Measurements--Nonrecurring Fair Value Measurements (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	drilling_rigs
Nonrecurring Fair Value Measurements [Line Items]	'	'	'
Liabilities incurred and assumed in current period	$2,313	$1,079	'
Number of drilling rigs no longer in service	3	'	'
Impairment losses	3,490	2,000	0
Significant unobservable inputs (Level 3) | Nonrecurring fair value measurements	'	'	'
Nonrecurring Fair Value Measurements [Line Items]	'	'	'
Annual inflation rate	2.95%	2.95%	'
Credit-adjusted risk-free interest rate	6.60%	7.10%	'
Liabilities incurred and assumed in current period	$2,313	$1,079	'

Fair_Value_MeasurementsCarryin

Fair Value Measurements--Carrying Value and Estimated Fair Value of Long-Term Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior secured revolving credit facility	$272,000	$25,000
9.875% Senior Notes due 2020	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	294,556	294,031
8.25% Senior Notes due 2021	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	555,719	556,631
Significant other observable inputs (Level 2) | Carrying value	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior secured revolving credit facility	272,000	25,000
Other secured long-term debt	16,437	17,740
Total long-term debt	1,538,712	1,293,402
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	294,556	294,031
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	400,000	400,000
Significant other observable inputs (Level 2) | Carrying value | 7.625% Senior Notes due 2022	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	555,719	556,631
Significant other observable inputs (Level 2) | Estimated fair value	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior secured revolving credit facility	272,000	25,000
Other secured long-term debt	16,437	17,740
Total long-term debt	1,648,852	1,392,740
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	340,140	341,250
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	437,000	434,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022	'	'
Fair Value of Other Financial Instruments [Line Items]	'	'
Senior Notes	$583,275	$574,750

Fair_Value_MeasurementsConcent

Fair Value Measurements--Concentrations of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	customers	customers	customers
Counterparty Credit Risk	'	'	'
Concentration Risk [Line Items]	'	'	'
Number of counterparties to derivative contracts	12	'	'
Number of counterparties to derivative contracts subject to offset under credit facility	11	'	'
Customer Concentration Risk	'	'	'
Concentration Risk [Line Items]	'	'	'
Number of significant purchasers	2	3	3
Commodity Sales | Customer A [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Percentage of sales to significant purchaser	20.10%	19.60%	15.10%
Commodity Sales | Customer B [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Percentage of sales to significant purchaser	19.10%	13.90%	13.60%
Commodity Sales | Customer C [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Percentage of sales to significant purchaser	'	12.70%	10.40%

Fair_Value_MeasurementsDerivat

Fair Value Measurements--Derivatives Offset in the Consolidated Balance Sheets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Disclosures [Abstract]	'	'
Derivative assets, gross	$13,113	$46,010
Derivative assets, amounts offset	-8,042	-4,721
Derivative assets, net of offsetting liabilities	5,071	41,289
Credit facility balance available to offset net derivative assets	-4,211	-9,180
Derivative assets, net of offsetting amounts outstanding under credit facility, not offset	860	32,109
Derivative liabilities, gross	-12,792	-5,605
Derivative liabilities, amounts offset	8,042	4,721
Derivative liabilities, net of offsetting assets	-4,750	-884
Derivative assets (liabilities), net	321	40,405
Derivative assets (liabilities), net of offsetting amounts outstanding under credit facility, not offset	($3,890)	$31,225

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]	'	'
Beginning balance	$49,214	$46,493
Liabilities incurred and assumed in current period	2,313	1,079
Revisions in estimated cash flows	6,723	0
Liabilities settled or disposed in current period	-7,016	-2,303
Accretion	3,945	3,945
Ending balance	55,179	49,214
Less current portion	1,874	2,900
Asset retirement obligations	53,305	46,314
Cash in escrow	$1,586	$1,631

Income_TaxesComponent_of_Incom

Income Taxes--Component of Income Tax Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current tax expense	'	'	'
Federal tax benefit	($29)	($23)	($21)
State tax expense	1,144	141	200
Current tax expense	1,115	118	179
Deferred tax expense	'	'	'
Federal tax expense	30,327	35,579	27,290
State tax expense	1,407	2,140	8,455
Deferred tax expense	31,734	37,719	35,745
Income tax expense	$32,849	$37,837	$35,924

Income_TaxesRate_Reconciliatio

Income Taxes--Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Line Items]	'	'	'
Statutory rate	35.00%	35.00%	35.00%
State income taxes, net of federal benefit	3.80%	2.10%	3.60%
Statutory depletion	-0.70%	-0.04%	-0.50%
Valuation allowance	-1.70%	0.00%	7.30%
Other	0.70%	-0.04%	0.70%
Effective tax rate	37.10%	37.00%	46.10%

Income_TaxesComponents_of_Defe

Income Taxes--Components of Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred Income Tax Assets And Liabilities [Line Items]	'	'
Asset retirement obligations	$8,777	$8,496
Accrued expenses, allowance and other	14,508	10,129
Derivative instruments	129	0
Net operating loss carryforwards - Federal	124,855	153,709
Net operating loss carryforwards - State	13,350	16,339
Statutory depletion carryforwards	2,867	2,242
Alternative minimum tax credit carryforwards	308	308
Deferred tax assets, gross	164,794	191,223
Less valuation allowance	-10,385	-11,858
Deferred tax asset	154,409	179,365
Derivative instruments	0	-32,438
Property and equipment	-206,799	-181,489
Inventories	-1,205	-1,211
Deferred tax liability	-208,004	-215,138
Net deferred tax liability	-53,595	-35,773
Net current deferred tax asset	9,260	0
Net current deferred tax liability	0	-26,872
Long-term deferred tax liability	($62,855)	($8,901)

Income_TaxesNarrative_Details

Income Taxes--Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Line Items]	'	'
Net current deferred tax asset	$9,260	$0
Net current deferred tax liability	0	-26,872
Deferred tax asset - account receivable	434	245
Change in valuation allowance on deferred tax asset	1,473	'
Derivative	'	'
Income Tax Disclosure [Line Items]	'	'
Net current deferred tax asset	2,252	'
Net current deferred tax liability	'	-33,066
Asset Retirement Obligation Costs	'	'
Income Tax Disclosure [Line Items]	'	'
Net current deferred tax asset	656	1,015
Internal Revenue Service (IRS)	'	'
Income Tax Disclosure [Line Items]	'	'
Operating loss carryforwards	357,000	'
Internal Revenue Service (IRS) | No Expiration	'	'
Income Tax Disclosure [Line Items]	'	'
Operating loss carryforwards	8,000	'
State and Local Jurisdiction	'	'
Income Tax Disclosure [Line Items]	'	'
Operating loss carryforwards	335,000	'
Operating loss carryforwards valuation allowance	($262,000)	'

StockBased_CompensationPhantom

Stock-Based Compensation--Phantom Stock and RSU Activity (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Phantom Shares | Phantom Stock Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Maximum percentage of fair market value of the Company available for share-based awards	2.00%	'	'
Maximum individual award as a percentage of shares available for award	5.00%	'	'
Award vesting period	'5 years	'	'
Days from vesting date to cash settlement	'120 days	'	'
Weighted average grant date fair value (per share)	'	'	'
Unvested and outstanding at beginning of period	$16.87	$16.37	$16.04
Granted	$0	$0	$18.55
Vested	$16.20	$14.38	$17.91
Forfeited	$17.57	$17.18	$16.98
Unvested and outstanding at end of period	$17.01	$16.87	$16.37
Shares	'	'	'
Unvested and outstanding at beginning of period (in shares)	84,764	125,768	126,859
Granted	0	0	37,316
Vested	-21,260	-26,908	-17,064
Forfeited	-10,342	-14,096	-21,343
Unvested and outstanding at end of period (in shares)	53,162	84,764	125,768
Vest date fair value	'	'	'
Vest date fair value	$273	$431	$309
Restricted Stock Units (RSU) | Restricted Stock Unit Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Maximum percentage of fair market value of the Company available for share-based awards	2.00%	'	'
Days from vesting date to cash settlement	'120 days	'	'
Weighted average grant date fair value (per share)	'	'	'
Unvested and outstanding at beginning of period	$17.12	$0	$0
Granted	$12.45	$17.07	$0
Vested	$17.12	$0	$0
Forfeited	$14.27	$16.80	$0
Unvested and outstanding at end of period	$13.53	$17.12	$0
Shares	'	'	'
Unvested and outstanding at beginning of period (in shares)	151,909	0	'
Granted	291,253	177,026	0
Vested	-50,246	0	0
Forfeited	-67,619	-25,117	0
Unvested and outstanding at end of period (in shares)	325,297	151,909	0
Vest date fair value	'	'	'
Vest date fair value	626	'	'
Phantom Stock and RSU | Phantom Stock Plan And Restricted Stock Unit Plan	'	'	'
Vest date fair value	'	'	'
Estimated fair value per share at end of period	$8.11	'	'
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$3,069	'	'
Maximum | Restricted Stock Units (RSU) | Restricted Stock Unit Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting period	'3 years	'	'

StockBased_Compensation2010_Eq

Stock-Based Compensation--2010 Equity Incentive Plan Summary and Modifications (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Reclassification from additional paid-in capital to stock-based compensation liabilities	$0	$0	$2,640
Class A Common Stock | 2010 Equity Incentive Plan | Restricted Stock	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Shares reserved for issuance under the 2010 Plan	86,301	'	'
Class A Common Stock | 2010 Equity Incentive Plan | Restricted Stock | Maximum	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting period	'5 years	'	'
Performance Vested, modified | 2010 Equity Incentive Plan | Restricted Stock	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Award vesting period	'5 years	'	'
Percentage of Performance Vested awards outstanding modified	20.00%	'	'
Incremental compensation cost	4,322	'	'
Performance Vested, modified | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target Five	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	400.00%	'	'
Performance Vested | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target One	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	175.00%	'	'
Vesting Percentage	20.00%	'	'
Performance Vested | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target Two	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	200.00%	'	'
Vesting Percentage	20.00%	'	'
Performance Vested | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target Three	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	250.00%	'	'
Vesting Percentage	20.00%	'	'
Performance Vested | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target Four	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	300.00%	'	'
Vesting Percentage	20.00%	'	'
Performance Vested | 2010 Equity Incentive Plan | Restricted Stock | Return On Investment Target Five	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Return On Investment Target Percentage	350.00%	'	'
Vesting Percentage	20.00%	'	'
Additional paid in capital	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Reclassification from additional paid-in capital to stock-based compensation liabilities	'	'	2,640
Additional paid in capital | 2010 Equity Incentive Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Reclassification from additional paid-in capital to stock-based compensation liabilities	'	'	$2,640

StockBased_CompensationVariabl

Stock-Based Compensation--Variables and Assumptions Used to Value Restricted Stock Awards (Details) (2010 Equity Incentive Plan, Restricted Stock, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Time Vested | Class A Common Stock	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Discount for lack of control	0.00%	23.00%	23.00%
Discount for lack of marketability	17.00%	22.00%	20.00%
Performance Vested	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Risk free interest rate, minimum	0.16%	0.25%	0.29%
Risk free interest rate, maximum	2.46%	1.21%	3.04%
Expected volatility, minimum	38.00%	42.00%	'
Expected volatility, maximum	39.00%	50.00%	'
Expected volatility	'	'	45.00%
Expected life	'5 years	'6 years	'7 years
Expected dividends	0	0	0

StockBased_CompensationSummary

Stock-Based Compensation--Summary of Time and Performance Award Activity (Detail) (Class A Common Stock, 2010 Equity Incentive Plan, Restricted Stock, USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Vest date fair value	'	'	'
Restricted stock used for tax withholding	1,025	1,469	528
Shares expected to be repurchased during the next twelve months	2,000	'	'
Time Vested	'	'	'
Weighted average grant date fair value (per share)	'	'	'
Unvested and outstanding at beginning of period	651.97	680.74	684.15
Granted	626.02	572.7	674.33
Vested	662.55	681.41	684.15
Forfeited	618.87	684.43	684.15
Modified	626	'	'
Unvested and outstanding at end of period	634.67	651.97	680.74
Shares	'	'	'
Unvested and outstanding at beginning of period (in shares)	9,481	11,585	10,049
Granted	2,839	2,444	4,030
Vested	-2,509	-2,673	-2,010
Forfeited	-1,734	-1,875	-484
Modified	11,169	'	'
Unvested and outstanding at end of period (in shares)	19,246	9,481	11,585
Vest date fair value	'	'	'
Vest date fair value	1,556	1,980	1,351
Estimated fair value per share at end of period	818.5	'	'
Aggregate intrinsic value of unvested shares outstanding	15,753	'	'
Performance Vested	'	'	'
Weighted average grant date fair value (per share)	'	'	'
Unvested and outstanding at beginning of period	298.15	298.15	295.1
Granted	181.59	394	307
Vested	0	0	0
Forfeited	340.23	295.96	295.1
Modified	324.47	'	'
Unvested and outstanding at end of period	307.45	298.15	298.15
Shares	'	'	'
Unvested and outstanding at beginning of period (in shares)	55,824	53,098	41,297
Granted	5,217	15,050	13,612
Vested	0	0	0
Forfeited	-3,171	-12,324	-1,811
Modified	-11,169	'	'
Unvested and outstanding at end of period (in shares)	46,701	55,824	53,098

StockBased_CompensationStockBa

Stock-Based Compensation--Stock-Based Compensation Cost (Detail) (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]	'	'	'
Stock-based compensation cost	$7,819	$4,982	$6,042
Less: stock-based compensation cost capitalized	-2,345	-1,917	-2,295
Stock-based compensation expense	5,474	3,065	3,747
Recognized tax benefit associated with stock-based compensation	2,031	1,230	1,547
Payments for share based compensation	1,533	1,386	661
Stock-based compensation costs included in accrued payroll and benefits payable	5,080	2,636	'
Unrecognized stock-based compensation cost	$15,867	'	'
Unrecognized compensation recognition period	'2 years 11 months 3 days	'	'

Stockholders_equity_Details

Stockholders' equity (Details) (USD $)

Dec. 31, 2013

Apr. 12, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Apr. 12, 2010

Apr. 12, 2010

Apr. 12, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 12, 2010

Jan. 12, 2014

Jan. 12, 2014

Jan. 12, 2014

Jan. 12, 2014

Jan. 13, 2014

Jan. 13, 2014

In Thousands, except Share data, unless otherwise specified

classes_of_stock

Class D Common Stock

Class D Common Stock

Class G Common Stock

Class G Common Stock

Class G Common Stock

Class G Common Stock

Class G Common Stock

Class B and C Common Stock

Class E Common Stock

Class E Common Stock

Class E Common Stock

Class B Common Stock

Class B Common Stock

Class B Common Stock

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Fischer Investments, L.L.C.

Altoma Energy GP

CHK Energy Holdings Inc.

Number of Directors Class of Stock Designates

Number of Directors Class of Stock Designates

Fischer Investments, L.L.C.

Healthcare of Ontario Pension Plan Trust Fund

CCMP

Class D Common Stock

Class G Common Stock

Directors

Directors

Times

CHK Energy Holdings Inc.

CHK Energy Holdings Inc.

Equity [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of classes of common stock

'

7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, par value

'

$0.01

$0.01

$0.01

$0.01

$0.01

'

'

'

'

$0.01

$0.01

'

$0.01

$0.01

'

'

'

'

'

'

'

Common stock issued to existing stockholders

'

'

'

'

'

'

1

1

1

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares of common stock sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

279,999

1

Minimum proceeds from Qualified IPO required to trigger share conversion

$250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of directors

'

'

'

'

'

'

'

'

'

3

'

'

2

'

'

'

'

'

'

'

'

'

Minimum percentage ownership of common stock owned as of the Closing Date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

Closing date of initial Stockholders Agreement

'

'4/12/2010

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum percentage of beneficial ownership required to retain rights and preferences under stockholders agreement

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

Maximum percentage of common stock that may be acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

Maximum percentage of common stock that may be sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

20.00%

'

'

Multiple of price per share paid by CCMP that must be received by the Company for Demand IPO

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.75

'

'

Related_party_transactions_Det

Related party transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Chesapeake	'	'	'
Related Party Transaction [Line Items]	'	'	'
Amounts receivable from Chesapeake	$466	$2,071	'
Amounts payable to Chesapeake	64	864	'
Chesapeake Holdings Corporation	'	'	'
Related Party Transaction [Line Items]	'	'	'
Chaparral common stock owned by Chesapeake	20.00%	'	'
Properties Operated by Chesapeake	'	'	'
Related Party Transaction [Line Items]	'	'	'
Revenue from jointly owned properties	7,428	3,625	5,028
Joint interest billings	-2,238	-4,896	-1,764
Properties Operated by Chaparral	'	'	'
Related Party Transaction [Line Items]	'	'	'
Revenue from jointly owned properties	-5,075	-4,084	-2,834
Joint interest billings	$9,689	$9,785	$4,056

Retirement_Benefits_Additional

Retirement Benefits - Additional information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Person	Person	Person
Disclosure Retirement Benefits Additional Information [Abstract]	'	'	'
Matched employee contribution	100.00%	'	'
Employee contribution on gross wages	7.00%	6.00%	6.00%
Number of employee participating in plan	585	661	625
Contribution expense	$3,621	$2,809	$2,390

Commitments_and_ContingenciesA

Commitments and Contingencies--Additional Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	compressor
	court_case
Loss Contingencies [Line Items]	'	'	'
Letters of credit outstanding	$920	$920	'
Interest paid	107,122	103,350	85,222
Leases, Operating [Abstract]	'	'	'
Rent expense	8,967	8,144	6,715
Maximum remaining term of operating leases	'5 years	'	'
Remaining payments associated with operating leases	955	'	'
Number of Assets	3	'	'
Litigation and Claims [Abstract]	'	'	'
Number of court cases	2	'	'
Minimum | Pending Litigation	'	'	'
Litigation and Claims [Abstract]	'	'	'
Damages sought	5,000	'	'
Letter of Credit	'	'	'
Loss Contingencies [Line Items]	'	'	'
Interest paid	$0	$0	$0
Short-Term [Member]	'	'	'
Leases, Operating [Abstract]	'	'	'
Number of short-term interim agreements	2	'	'

Commitments_and_ContingenciesC

Commitments and Contingencies--Commitments (Details) (C O 2 Purchase Contract, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf
	supplier
	contract
Long-term Purchase Commitment [Line Items]	'	'	'
Number of CO2 purchase contracts	4	'	'
Number of suppliers	4	'	'
Commitment period	'10 years	'	'
Potential purchase volume rate reduction	100.00%	'	'
Notice required for purchase volume rate reduction	'6 months	'	'
Average volume purchased (MMcf/d)	73	'	'
Purchases under CO2 contracts	$3,849	$3,860	$5,011
2014	2,506	'	'
2015	2,552	'	'
2016	1,289	'	'
2017	1,289	'	'
2018	2,008	'	'
2019 and thereafter	10,186	'	'
Total estimated minimum purchase obligations under CO2 contracts	$19,830	'	'
Minimum	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Contract term	'P2Y	'	'
Maximum	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Contract term	'P20Y	'	'
First Contract Year | Minimum	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Minimum volume required (MMcf/d)	24	'	'
Remaining Contract Term	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Average volume purchased (MMcf/d)	72	'	'
Remaining Contract Term | Minimum	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Minimum volume required (MMcf/d)	35	'	'
Fixed Price [Member]	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Number of CO2 purchase contracts	1	'	'
Variable Price [Member]	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Number of CO2 purchase contracts	2	'	'

Recovered_Sheet7

Oil and Natural Gas Activities--Costs Incurred (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Property acquisition costs	'		'		'
Proved properties	$69,962		$1,108		$1,024
Unproved properties	145,853		46,895		15,795
Total acquisition costs	215,815		48,003		16,819
Development costs	376,394		409,429		250,182
Exploration costs	77,507	[1]	54,432	[1]	57,016	[1]
Total	$669,716		$511,864		$324,017
[1]	Includes $37,344, $52,188, and $33,030 of EOR costs in 2013, 2012, and 2011, respectively.

Recovered_Sheet8

Oil and Natural Gas Activities--Costs Incurred Footnote (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Oil and Gas In Process Activities [Line Items]	'		'		'
Exploration costs	$77,507	[1]	$54,432	[1]	$57,016	[1]
Enhanced Oil Recovery	'		'		'
Oil and Gas In Process Activities [Line Items]	'		'		'
Exploration costs	$37,344		$52,188		$33,030
[1]	Includes $37,344, $52,188, and $33,030 of EOR costs in 2013, 2012, and 2011, respectively.

Oil_and_Natural_Gas_Activities2

Oil and Natural Gas Activities--Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Depreciation, depletion, and amortization expense of oil and natural gas properties	$179,734	$154,788	$132,307
Average depreciation, depletion and amortization rate per equivalent unit of production	18.45	16.98	15.29
Unproved property costs excluded from amortization	321,477	162,921	'
Incurred During Current Reporting Period	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property costs excluded from amortization	169,044	'	'
Incurred One Year Prior To Current Reporting Period	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property costs excluded from amortization	114,406	'	'
Incurred Two Years Prior To Current Reporting Period	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property costs excluded from amortization	9,372	'	'
Incurred More Than Two Years Prior To Current Reporting Period	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Unproved property costs excluded from amortization	$28,655	'	'
Minimum	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Evaluation period of oil and natural gas properties (in years)	'2 years	'	'
Maximum	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Evaluation period of oil and natural gas properties (in years)	'5 years	'	'

Recovered_Sheet9

Disclosures about Oil and Natural Gas Activities (Unaudited)--Summary of Changes in Quantities of Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBoe		MBoe	MBoe	MBoe
Reserve Quantities [Line Items]	'		'	'	'
Balance at beginning of period (MBoe)	146,095		156,260	149,282	'
Purchase of minerals in place (MBoe)	4,945		9	378	'
Sales of minerals in place (MBoe)	-7,116		-3,795	-3,544	'
Extensions and discoveries (MBoe)	25,085		13,326	13,178	'
Revisions (MBoe)	-4,671		-11,429	4,564	'
Improved recoveries (MBoe)	3,879		842	1,057	'
Production (MBoe)	-9,742		-9,118	-8,655	'
Balance at end of period (MBoe)	158,475		146,095	156,260	'
Proved developed reserves (MBoe)	100,664		94,927	100,118	98,566
Proved undeveloped reserves (MBoe)	57,811		51,169	56,142	50,716
Oil (including natural gas liquids)	'		'	'	'
Reserve Quantities [Line Items]	'		'	'	'
Balance at beginning of period	'		100,380	93,412	'
Purchase of minerals in place	'		0	241	'
Sales of minerals in place	'		-2,694	-2,355	'
Extensions and discoveries	'		7,117	6,362	'
Revisions	'		-3,410	-6,711	'
Improved recoveries	'		842	1,057	'
Production	'		-5,812	-5,048	'
Balance at end of the period	'		103,243	100,380	'
Proved developed reserves	'		62,450	55,607	'
Proved undeveloped reserves	'		39,287	37,930	37,805
Natural Gas	'		'	'	'
Reserve Quantities [Line Items]	'		'	'	'
Balance at beginning of period	257,115		335,280	335,220	'
Purchase of minerals in place	3,618		57	822	'
Sales of minerals in place	-9,708		-6,608	-7,134	'
Extensions and discoveries	62,412		37,256	40,896	'
Revisions	-9,735	[1]	89,036	12,882	'
Improved recoveries	0		0	0	'
Production	-20,250		-19,834	-21,642	'
Balance at end of the period	302,922		257,115	335,280	'
Proved developed reserves	185,826		226,008	257,754	'
Proved undeveloped reserves	106,002		71,289	109,272	77,466
Oil	'		'	'	'
Reserve Quantities [Line Items]	'		'	'	'
Balance at beginning of period	92,047		'	'	'
Purchase of minerals in place	3,283		'	'	'
Sales of minerals in place	-5,174		'	'	'
Extensions and discoveries	11,556		'	'	'
Revisions	7,772	[1]	'	'	'
Improved recoveries	3,879		'	'	'
Production	-5,006		'	'	'
Balance at end of the period	92,813		'	'	'
Proved undeveloped reserves	36,453		'	'	'
Natural Gas Liquids	'		'	'	'
Reserve Quantities [Line Items]	'		'	'	'
Balance at beginning of period	11,195	[2]	'	'	'
Purchase of minerals in place	1,059	[2]	'	'	'
Sales of minerals in place	-324	[2]	'	'	'
Extensions and discoveries	3,127	[2]	'	'	'
Revisions	-1,479	[1],[2]	'	'	'
Improved recoveries	0	[2]	'	'	'
Production	-1,361	[2]	'	'	'
Balance at end of the period	15,175	[2]	'	'	'
Proved undeveloped reserves	3,691	[2]	'	'	'
[1]	Includes natural gas liquids.
[2]	The downward revision in our oil reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and to negative technical revisions. These downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.

Recovered_Sheet10

Disclosures about Oil and Natural Gas Activities (Unaudited)--Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash flows	$10,660,532	$9,690,171	$10,737,829
Future production costs	3,841,723	3,737,069	4,061,713
Future development and abandonment costs	1,506,585	1,172,786	1,202,438
Future income tax provisions	1,328,925	1,223,036	1,653,666
Net future cash flows	3,983,299	3,557,280	3,820,012
Less effect of 10% discount factor	-2,239,527	-2,033,599	-2,222,100
Standardized measure of discounted future net cash flows	$1,743,772	$1,523,681	$1,597,912

Disclosures_about_Oil_and_Natu2

Disclosures about Oil and Natural Gas Activities (Unaudited)--Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]	'	'	'
Beginning of year	$1,523,681	$1,597,912	$1,236,026
Sale of oil and natural gas produced, net of production costs	-418,224	-346,627	-374,300
Net changes in prices and production costs	172,975	-206,640	538,466
Extensions and discoveries	514,743	224,903	224,027
Improved recoveries	79,589	14,204	17,969
Changes in future development costs	-236,121	-18,184	-238,881
Development costs incurred during the period that reduced future development costs	110,354	118,502	166,161
Revisions of previous quantity estimates	-95,855	-192,894	77,588
Purchases and sales of reserves in place, net	-20,021	-54,070	-40,662
Accretion of discount	152,830	214,794	169,679
Net change in income taxes	-60,981	166,238	-177,142
Changes in production rates and other	20,802	5,543	-1,019
End of year	$1,743,772	$1,523,681	$1,597,912

Disclosures_about_Oil_and_Natu3

Disclosures about Oil and Natural Gas Activities (Unaudited)--Prices Used in Determining Future Net Revenues (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Oil	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	96.78		'		'
Oil (including natural gas liquids)	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	'		94.71		96.19
Natural Gas	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	3.67		2.76		4.11
Natural Gas Liquids	'		'		'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'		'		'
Price before field differentials used in determining future net revenues	32.53	[1]	0	[1]	0	[1]
[1]	The NGL price is provided only for 2013 to coincide with our separate presentation of NGL reserves in that year.