Chaparral Energy (CHAP) 10-Q 12 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document	3 Months Ended
	Mar. 31, 2015	12-May-15
Entity Information [Line Items]
Entity Registrant Name	Chaparral Energy, Inc.
Entity Central Index Key	1346980
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	FALSE
Common Class A
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		348,507
Common Class B
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		344,859
Common Class C
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		209,882
Common Class E
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		504,276
Common Class F
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		1
Common Class G
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		2

Consolidated_balance_sheets

Consolidated balance sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$42,173	$31,492
Accounts receivable, net	102,581	98,444
Inventories, net	27,162	25,557
Prepaid expenses	3,321	4,484
Derivative instruments	166,873	179,921
Total current assets	342,110	339,898
Property and equipment—at cost, net	64,397	66,561
Oil and natural gas properties, using the full cost method:
Proved	3,825,904	3,735,817
Unevaluated (excluded from the amortization base)	265,109	288,425
Accumulated depreciation, depletion, amortization and impairment	-1,763,747	-1,701,851
Total oil and natural gas properties	2,327,266	2,322,391
Derivative instruments	70,228	71,710
Other assets	30,120	31,256
Total assets	2,834,121	2,831,816
Liabilities and stockholders’ equity
Accounts payable and accrued liabilities	90,916	191,957
Accrued payroll and benefits payable	13,550	21,654
Accrued interest payable	33,724	24,106
Revenue distribution payable	17,869	24,467
Current maturities of long-term debt and capital leases	5,138	5,377
Derivative instruments	0	77
Deferred income taxes	60,072	60,728
Total current liabilities	221,269	328,366
Long-term debt and capital leases, less current maturities	1,730,166	1,628,425
Stock-based compensation	537	3,131
Asset retirement obligations	45,020	43,277
Deferred income taxes	119,967	116,759
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	430,734	429,678
Retained earnings	286,414	282,166
Total stockholders' equity	717,162	711,858
Total liabilities and stockholders' equity	2,834,121	2,831,816
Common Class A
Stockholders’ equity:
Common stock	4	4
Common Class B
Stockholders’ equity:
Common stock	3	3
Common Class C
Stockholders’ equity:
Common stock	2	2
Common Class E
Stockholders’ equity:
Common stock	5	5
Common Class F
Stockholders’ equity:
Common stock	0	0
Common Class G
Stockholders’ equity:
Common stock	$0	$0

Consolidated_balance_sheets_Pa

Consolidated balance sheets (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Preferred stock, shares authorized	600,000	600,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common Class A
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	352,792	364,896
Common stock, shares outstanding	352,792	364,896
Common Class B
Common stock, par value	0.01	0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	344,859	344,859
Common stock, shares outstanding	344,859	344,859
Common Class C
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
Common Class E
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
Common Class F
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
Common Class G
Common stock, par value	0.01	0.01
Common stock, shares authorized	3	3
Common stock, shares issued	2	2
Common stock, shares outstanding	2	2

Consolidated_statements_of_ope

Consolidated statements of operations (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Commodity sales	$93,079	$173,339
Total revenues	93,079	173,339
Costs and expenses:
Lease operating	31,632	33,655
Transportation and processing	2,372	1,366
Production taxes	4,484	6,643
Depreciation, depletion & amortization	65,211	55,750
General and administrative	9,194	13,387
Cost reduction initiatives	8,774	0
Total costs and expenses	121,667	110,801
Operating income	-28,588	62,538
Non-operating income (expense):
Interest expense	-26,712	-26,459
Non-hedge derivative gains (losses)	61,431	-29,199
Other income, net	674	160
Net non-operating income (expense)	35,393	-55,498
Income before income taxes	6,805	7,040
Income tax expense	2,557	2,635
Net income	$4,248	$4,405

Consolidated_statements_of_cas

Consolidated statements of cash flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities
Net income	$4,248	$4,405
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization	65,211	55,750
Deferred income taxes	2,553	2,485
Non-hedge derivative (gains) losses	-61,431	29,199
Gain on sale of assets	-79	-84
Other	1,221	492
Change in assets and liabilities
Accounts receivable	-8,126	-15,762
Inventories	-6,431	-4,234
Prepaid expenses and other assets	1,116	669
Accounts payable and accrued liabilities	-2,808	2,303
Revenue distribution payable	-6,598	-1,679
Stock-based compensation	-1,898	695
Net cash (used in) provided by operating activities	-13,022	74,239
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	-156,798	-138,669
Proceeds from asset dispositions	3,068	16,997
Settlement of non-hedge derivative instruments	75,885	-8,755
Net cash used in investing activities	-77,845	-130,427
Cash flows from financing activities
Proceeds from long-term debt	103,000	50,603
Repayment of long-term debt	-860	-3,783
Principal payments under capital lease obligations	-592	-570
Net cash provided by financing activities	101,548	46,250
Net increase (decrease) in cash and cash equivalents	10,681	-9,938
Cash and cash equivalents at beginning of period	31,492	48,595
Cash and cash equivalents at end of period	$42,173	$38,657

Nature_of_operations_and_summa

Nature of operations and summary of significant accounting policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Nature of operations and summary of significant accounting policies	Nature of operations and summary of significant accounting policies
	Nature of operations
	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. Our properties are located primarily in Oklahoma and Texas.
	Interim financial statements
	The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.
	The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. In management’s opinion, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.
	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 March 31, 2015, cash with a recorded balance totaling $38,551 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 our assessment of the owner’s ability to pay its obligation, among other things.
	We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.
	Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014:
		March 31,				December 31,
		2015				2014
	Joint interests	$	21,844			$	30,648
	Accrued commodity sales	37,968				45,667
	Derivative settlements	41,092				19,678
	Other	2,014				2,738
	Allowance for doubtful accounts	(337		)		(287		)
		$	102,581			$	98,444
	Inventories
	Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is 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. Inventories at March 31, 2015 and December 31, 2014 consisted of the following:
			March 31,				December 31,
			2015				2014
	Equipment inventory		$	25,518			$	24,169
	Commodities		2,821				2,575
	Inventory valuation allowance		(1,177		)		(1,187		)
			$	27,162			$	25,557
	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 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 March 31, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $26,023 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 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 March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.
	Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. 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.
	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, stock-based compensation expense could have been significantly impacted if other assumptions had been used.
	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.
	Cost reduction initiatives
	Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.
	Recently adopted accounting pronouncements
	In July 2011, the Financial Accounting Standards Board (“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, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.
	Recently issued accounting pronouncements
	In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.
	In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.
	In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

Supplemental_disclosures_to_th

Supplemental disclosures to the consolidated statements of cash flows	3 Months Ended
	Mar. 31, 2015
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:
		Three months ended March 31,
		2015			2014
	Net cash provided by operating activities included:
	Cash payments for interest	$	19,073		$	18,794
	Interest capitalized	(3,462		)	(2,942		)
	Cash payments for interest, net of amounts capitalized	$	15,611		$	15,852
	Non-cash investing activities included:
	Asset retirement obligation additions and revisions	$	539		$	139
	Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	—		$	18,629

Longterm_debt

Long-term debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Long-term debt	Long-term debt
	As of the dates indicated, long-term debt consisted of the following:
		March 31, 2015		December 31, 2014
	9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
	8.25% Senior Notes due 2021	400,000		400,000
	7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
	Senior secured revolving credit facility	450,000		347,000
	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	10,577		10,705
	Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment	3,522		4,252
	Capital lease obligations	21,245		21,837
		1,735,304		1,633,802
	Less current maturities	5,138		5,377
		$	1,730,166	$	1,628,425
	Senior Notes
	The senior notes, which, as of March 31, 2015, 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 our existing and future senior debt, and rank senior to all of our existing and future subordinated debt.
	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. During the three months ended March 31, 2015, we borrowed $103,000 on our senior secured revolving credit facility. As of March 31, 2015, the weighted average interest rate was 2.2% on outstanding borrowings under the senior secured revolving credit facility.
	Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semiannually 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. Our first semiannual borrowing base redetermination for the current year was finalized ahead of schedule in conjunction with an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”), effective on April 1, 2015. As of result of our semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015.
	In connection with the Fifteenth Amendment, the Consolidated Net Debt to Consolidated EBITDAX covenant required by our senior secured revolving credit facility will be replaced by a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.0. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised in the amendment to now include both secured and unsecured debt.
	We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 2015.
	Capital Leases
	During 2013, 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 natural 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 approximately $3,181 annually.

Derivative_instruments

Derivative instruments	3 Months Ended
	Mar. 31, 2015
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, natural gas. and natural gas liquids. 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. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.
	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.
	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 pay 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. A put spread may also be constructed by entering into separate sold put and purchased put contracts.
	Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or deferring payment until the put options settle. 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 in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or three-way collars. The fair value of our put options include any deferred premiums that are payable under the contract.
	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.
	The following table summarizes our crude oil derivatives outstanding as of March 31, 2015:
						Weighted average fixed price per Bbl
	Period and type of contract		Volume			Swaps				Sold puts		Purchased puts		Sold calls			Average premium
			MBbls
	2015
	Swaps		450			$	95.25			$	—	$	—	$	—		$	—
	Swaps with deferred premium (1)		4,028			$	92.78			$	—	$	—	$	—		$	13.8
	2016
	Three-way collars		240			$	—			$	84	$	92	$	101.01		$	—
	Enhanced swaps (2)		3,720			$	92.94			$	80.52	$	—	$	—		$	—
	Purchased puts (2)		3,720			$	—			$	—	$	60	$	—		$	5.54
	___________
	-1	As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.
	-2	Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.
	The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:
	Period and type of contract		Volume			Weighted
			BBtu			average
						fixed price
						per MMBtu
	2015
	Natural gas swaps		12,240			$	4.15
	Natural gas basis protection swaps		10,800			$	0.24
	2016
	Natural gas swaps		14,000			$	4.19
	Natural gas basis protection swaps		8,400			$	0.36
	2017
	Natural gas swaps		12,700			$	3.64
	2018
	Natural gas swaps		8,250			$	3.83
	On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas, receiving net proceeds of $15,395, in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in non-hedge derivative gains (losses) disclosed below.
	Effect of derivative instruments on the consolidated balance sheets
	All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5—Fair value measurements for additional information regarding fair value measurements. 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 March 31, 2015										As of December 31, 2014
		Assets				Liabilities				Net value		Assets		Liabilities				Net value
	Natural gas swaps	$	37,843			$	—			$	37,843	$	32,939	$	—			$	32,939
	Oil swaps	19,168				—				19,168		23,465		—				23,465
	Oil collars	1,700				—				1,700		1,175		—				1,175
	Oil enhanced swaps	91,362				—				91,362		100,724		—				100,724
	Oil purchased puts	85,987				—				85,987		93,268		—				93,268
	Natural gas basis differential swaps	1,041				—				1,041		292		(309		)		(17		)
	Total derivative instruments	237,101				—				237,101		251,863		(309		)		251,554
	Less:
	Netting adjustments (1)	—				—				—		232		(232		)		—
	Current portion asset (liability)	166,873				—				166,873		179,921		(77		)		179,844
		$	70,228			$	—			$	70,228	$	71,710	$	—			$	71,710
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
	Derivative settlements outstanding at March 31, 2015 and December 31, 2014 were as follows:
		March 31,				December 31,
		2015				2014
	Derivative settlements receivable included in accounts receivable	$	41,092			$	19,678
	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.
	Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:
			Three months ended
			March 31,
		2015				2014
Change in fair value of commodity price swaps		$	606			$	(5,193	)
Change in fair value of collars		525				(2,863		)
Change in fair value of enhanced swaps and put options		(16,643		)		(10,527		)
Change in fair value of natural gas basis differential contracts		1,058				(1,861		)
Receipts from (payments on) settlement of commodity price swaps		19,027				(5,850		)
Payments on settlement of collars		—				(41		)
Receipts from (payments on) settlement of enhanced swaps and put options		56,949				(1,992		)
Payments on settlement of natural gas basis differential contracts		(91		)		(872		)
		$	61,431			$	(29,199	)

Fair_value_measurements

Fair value measurements	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
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.
	Fair value measurements 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 as follows:
	•	Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
	•	Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability.
	•	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.
	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.
	Recurring fair value measurements
	Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4—Derivative instruments). We have no Level 1 assets or liabilities as of March 31, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of March 31, 2015 and December 31, 2014 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 March 31, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts and purchased puts. 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 recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.
	The fair value hierarchy for our financial assets and liabilities is shown by the following table:
		As of March 31, 2015												As of December 31, 2014
		Derivative				Derivative				Net assets				Derivative			Derivative				Net assets
		assets				liabilities				(liabilities)				assets			liabilities				(liabilities)
	Significant other observable inputs (Level 2)	$	58,052			$	—			$	58,052			$	56,696		$	(309	)		$	56,387
	Significant unobservable inputs (Level 3)	179,049				—				179,049				195,167			—				195,167
	Netting adjustments (1)	—				—				—				(232		)	232				—
		$	237,101			$	—			$	237,101			$	251,631		$	(77	)		$	251,554
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.
	Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2015 and 2014 were:
			Three months ended March 31,
	Net derivative assets (liabilities)		2015				2014
	Beginning balance		$	195,167			$	3,622
	Realized and unrealized gains (losses) included in non-hedge derivative losses		40,831				(15,423		)
	Settlements (received) paid		(56,949		)		2,033
	Ending balance		$	179,049			$	(9,768	)
	Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period		$	14,639			$	(15,324	)
	Nonrecurring fair value measurements
	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 first three months of 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 12.40% and 5.80%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 6—Asset retirement obligations for additional information regarding our asset retirement obligations.
	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 March 31, 2015 and December 31, 2014 were as follows:
			March 31, 2015								December 31, 2014
	Level 2		Carrying				Estimated				Carrying				Estimated
			value				fair value				value				fair value
	9.875% Senior Notes due 2020		$	295,294			$	228,480			$	295,139			$	269,091
	8.25% Senior Notes due 2021		400,000				278,000				400,000				270,000
	7.625% Senior Notes due 2022		554,666				368,500				554,869				379,775
	Senior secured revolving credit facility		450,000				450,000				347,000				347,000
	Other secured long-term debt		14,099				14,099				14,957				14,957
			$	1,714,059			$	1,339,079			$	1,611,965			$	1,280,823
	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.
	Counterparty credit risk
	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 amounts owed to such counterparty lender under our senior secured revolving credit facility. As of March 31, 2015, the counterparties to our open derivative contracts consisted of eight financial institutions, of which eight 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)				Derivatives(1)			Amounts outstanding under senior secured revolving credit facility				Net amount
	As of March 31, 2015
	Derivative assets		$	237,101			$	—			$	237,101			$	—		$	(140,962	)		$	96,139
	Derivative liabilities		—				—				—				—			—				—
			$	237,101			$	—			$	237,101			$	—		$	(140,962	)		$	96,139
	As of December 31, 2014
	Derivative assets		$	251,863			$	(232	)		$	251,631			$	—		$	(118,430	)		$	133,201
	Derivative liabilities		(309		)		232				(77		)		—			—				(77		)
			$	251,554			$	—			$	251,554			$	—		$	(118,430	)		$	133,124
	___________
	-1	Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.
	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 nil at March 31, 2015.

Asset_retirement_obligations

Asset retirement obligations	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations
	The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2015 and 2014.
		Three months ended March 31,
		2015			2014
	Beginning balance	$	47,424		$	55,179
	Liabilities incurred in current period	141			139
	Liabilities settled and disposed in current period	(3,030		)	(170		)
	Revisions in estimated cash flows	398			—
	Accretion expense	931			1,074
	Ending balance	45,864			56,222
	Less current portion included in accounts payable and accrued liabilities	844			1,874
		$	45,020		$	54,348
	See Note 5—Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

Stockbased_compensation

Stock-based compensation	3 Months Ended
	Mar. 31, 2015
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 “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Phantom 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.
	Under the RSU Plan, restricted stock units may be awarded to Participants in an aggregate amount of 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 months ended March 31, 2015 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, 2015	$	20.18			23,179					$	9.91	569,160
	Granted	—				—					15.26		52,711
	Vested	24.48				(6,649	)		$	25	10.58		(206,332	)	$	790
	Forfeited	17.99				(4,907	)				9.62		(105,159	)
	Unvested and outstanding at March 31, 2015	$	18.64			11,623					$	10.48	310,380
	Based on an estimated fair value of $2.92 per phantom share and RSU as of March 31, 2015, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $940.
	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 affiliates’ 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.
	Our 2010 Plan allows participants 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. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.
	We have previously modified the vesting conditions of awards granted under the 2010 Plan. Please see “Note 10—Stock-based compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2014, for a discussion of the modifications.
	A summary of our restricted stock activity during the three months ended March 31, 2015 is presented below:
		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, 2015	$	791.52			25,834					$	292.92	38,943
	Granted	533.8				610					306.5		599
	Vested	794.4				(6,354	)		$	3,392	—		—
	Forfeited	764.16				(3,190	)				310.57		(8,719	)
	Unvested and total outstanding at March 31, 2015	$	786.3			16,900					$	288.19	30,823
	During the three months ended March 31, 2015 and 2014, respectively, we repurchased and canceled 1,404 and 1,068 vested shares, primarily for tax withholding, and we expect to repurchase and cancel approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $533.80 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $9,021 as of March 31, 2015.
	Stock-based compensation cost
	Compensation cost 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.
	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 periods indicated:
			Three months ended
			March 31,
			2015				2014
	Stock-based compensation cost		$	(1,500	)		$	2,531
	Less: stock-based compensation cost capitalized		415				(962		)
	Stock-based compensation expense		$	(1,085	)		$	1,569
	Payments for stock-based compensation		$	812			$	874
	We recorded a credit to our stock-based compensation expense for the three months ended March 31, 2015, due to forfeitures that occurred in conjunction with our workforce reduction in February 2015 and due to a decrease in the per-unit value of our phantom stock and RSU awards. As of March 31, 2015 and December 31, 2014, accrued payroll and benefits payable included $4,056 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $14,793 is expected to be recognized over a weighted average period of 2.3 years.

Commitments_and_contingencies

Commitments and contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies
	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 $874 and $920 as of March 31, 2015 and December 31, 2014, respectively. Interest on each Letter accrues at the lender’s prime rate plus applicable margin 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 three months ended March 31, 2015 or 2014.
	Litgation 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, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated that, if the class is certified, they seek damages in excess of $5,000 which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
	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, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
	Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. We have joined in Motions to Dismiss filed by the other defendants. 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. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
	We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.
	We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO2 recycle compressors at our EOR facilities and office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO2, drilling rig services, pipe and equipment. Other than additional debt borrowings during the three months ended March 31, 2015, there were no material changes to our contractual commitments since December 31, 2014.

Nature_of_operations_and_summa1

Nature of operations and summary of significant accounting policies (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Nature of operations	Nature of operations
	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. Our properties are located primarily in Oklahoma and Texas.
Interim financial statements	Interim financial statements
	The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014.
	The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. In management’s opinion, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.
Reclassification	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	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.
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 our assessment of the owner’s ability to pay its obligation, among other things.
	We write off accounts receivable when they are determined to be uncollectible. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.
Inventories	Inventories
	Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is 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.
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 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 March 31, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $26,023 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 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 March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.
	Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. 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.
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, stock-based compensation expense could have been significantly impacted if other assumptions had been used.
	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.
Cost reduction initiatives	Cost reduction initiatives
	Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.
Recently adopted and recently issued accounting pronouncements	Recently adopted accounting pronouncements
	In July 2011, the Financial Accounting Standards Board (“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, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.
	Recently issued accounting pronouncements
	In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.
	In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.
	In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

Nature_of_operations_and_summa2

Nature of operations and summary of significant accounting policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Components of accounts receivable	Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014:
		March 31,				December 31,
		2015				2014
	Joint interests	$	21,844			$	30,648
	Accrued commodity sales	37,968				45,667
	Derivative settlements	41,092				19,678
	Other	2,014				2,738
	Allowance for doubtful accounts	(337		)		(287		)
		$	102,581			$	98,444
Components of inventory	Inventories at March 31, 2015 and December 31, 2014 consisted of the following:
			March 31,				December 31,
			2015				2014
	Equipment inventory		$	25,518			$	24,169
	Commodities		2,821				2,575
	Inventory valuation allowance		(1,177		)		(1,187		)
			$	27,162			$	25,557

Supplemental_disclosures_to_th1

Supplemental disclosures to the consolidated statements of cash flows (Tables)	3 Months Ended
	Mar. 31, 2015
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:
		Three months ended March 31,
		2015			2014
	Net cash provided by operating activities included:
	Cash payments for interest	$	19,073		$	18,794
	Interest capitalized	(3,462		)	(2,942		)
	Cash payments for interest, net of amounts capitalized	$	15,611		$	15,852
	Non-cash investing activities included:
	Asset retirement obligation additions and revisions	$	539		$	139
	Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$	—		$	18,629

Longterm_debt_Tables

Long-term debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Components of long-term debt	As of the dates indicated, long-term debt consisted of the following:
		March 31, 2015		December 31, 2014
	9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively	$	295,294	$	295,139
	8.25% Senior Notes due 2021	400,000		400,000
	7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively	554,666		554,869
	Senior secured revolving credit facility	450,000		347,000
	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	10,577		10,705
	Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment	3,522		4,252
	Capital lease obligations	21,245		21,837
		1,735,304		1,633,802
	Less current maturities	5,138		5,377
		$	1,730,166	$	1,628,425

Derivative_instruments_Tables

Derivative instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding derivative instruments	The following table summarizes our crude oil derivatives outstanding as of March 31, 2015:
						Weighted average fixed price per Bbl
	Period and type of contract		Volume			Swaps				Sold puts		Purchased puts		Sold calls			Average premium
			MBbls
	2015
	Swaps		450			$	95.25			$	—	$	—	$	—		$	—
	Swaps with deferred premium (1)		4,028			$	92.78			$	—	$	—	$	—		$	13.8
	2016
	Three-way collars		240			$	—			$	84	$	92	$	101.01		$	—
	Enhanced swaps (2)		3,720			$	92.94			$	80.52	$	—	$	—		$	—
	Purchased puts (2)		3,720			$	—			$	—	$	60	$	—		$	5.54
	___________
	-1	As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.
	-2	Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.
	The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:
	Period and type of contract		Volume			Weighted
			BBtu			average
						fixed price
						per MMBtu
	2015
	Natural gas swaps		12,240			$	4.15
	Natural gas basis protection swaps		10,800			$	0.24
	2016
	Natural gas swaps		14,000			$	4.19
	Natural gas basis protection swaps		8,400			$	0.36
	2017
	Natural gas swaps		12,700			$	3.64
	2018
	Natural gas swaps		8,250			$	3.83
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 March 31, 2015										As of December 31, 2014
		Assets				Liabilities				Net value		Assets		Liabilities				Net value
	Natural gas swaps	$	37,843			$	—			$	37,843	$	32,939	$	—			$	32,939
	Oil swaps	19,168				—				19,168		23,465		—				23,465
	Oil collars	1,700				—				1,700		1,175		—				1,175
	Oil enhanced swaps	91,362				—				91,362		100,724		—				100,724
	Oil purchased puts	85,987				—				85,987		93,268		—				93,268
	Natural gas basis differential swaps	1,041				—				1,041		292		(309		)		(17		)
	Total derivative instruments	237,101				—				237,101		251,863		(309		)		251,554
	Less:
	Netting adjustments (1)	—				—				—		232		(232		)		—
	Current portion asset (liability)	166,873				—				166,873		179,921		(77		)		179,844
		$	70,228			$	—			$	70,228	$	71,710	$	—			$	71,710
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
Derivative settlements outstanding	Derivative settlements outstanding at March 31, 2015 and December 31, 2014 were as follows:
		March 31,				December 31,
		2015				2014
	Derivative settlements receivable included in accounts receivable	$	41,092			$	19,678
Non-hedge derivative gains (losses) in the consolidated statements of operations	Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:
			Three months ended
			March 31,
			2015				2014
	Change in fair value of commodity price swaps		$	606			$	(5,193	)
	Change in fair value of collars		525				(2,863		)
	Change in fair value of enhanced swaps and put options		(16,643		)		(10,527		)
	Change in fair value of natural gas basis differential contracts		1,058				(1,861		)
	Receipts from (payments on) settlement of commodity price swaps		19,027				(5,850		)
	Payments on settlement of collars		—				(41		)
	Receipts from (payments on) settlement of enhanced swaps and put options		56,949				(1,992		)
	Payments on settlement of natural gas basis differential contracts		(91		)		(872		)
			$	61,431			$	(29,199	)

Fair_value_measurements_Tables

Fair value measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair value hierarchy for financial instruments measured at fair value on a recurring basis	The fair value hierarchy for our financial assets and liabilities is shown by the following table:
		As of March 31, 2015												As of December 31, 2014
		Derivative				Derivative				Net assets				Derivative			Derivative				Net assets
		assets				liabilities				(liabilities)				assets			liabilities				(liabilities)
	Significant other observable inputs (Level 2)	$	58,052			$	—			$	58,052			$	56,696		$	(309	)		$	56,387
	Significant unobservable inputs (Level 3)	179,049				—				179,049				195,167			—				195,167
	Netting adjustments (1)	—				—				—				(232		)	232				—
		$	237,101			$	—			$	237,101			$	251,631		$	(77	)		$	251,554
	___________
	-1	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.
Level 3 rollforward	Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2015 and 2014 were:
			Three months ended March 31,
	Net derivative assets (liabilities)		2015				2014
	Beginning balance		$	195,167			$	3,622
	Realized and unrealized gains (losses) included in non-hedge derivative losses		40,831				(15,423		)
	Settlements (received) paid		(56,949		)		2,033
	Ending balance		$	179,049			$	(9,768	)
	Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period		$	14,639			$	(15,324	)
Fair value of other financial instruments	The carrying value and estimated fair value of our long-term debt at March 31, 2015 and December 31, 2014 were as follows:
			March 31, 2015								December 31, 2014
	Level 2		Carrying				Estimated				Carrying				Estimated
			value				fair value				value				fair value
	9.875% Senior Notes due 2020		$	295,294			$	228,480			$	295,139			$	269,091
	8.25% Senior Notes due 2021		400,000				278,000				400,000				270,000
	7.625% Senior Notes due 2022		554,666				368,500				554,869				379,775
	Senior secured revolving credit facility		450,000				450,000				347,000				347,000
	Other secured long-term debt		14,099				14,099				14,957				14,957
			$	1,714,059			$	1,339,079			$	1,611,965			$	1,280,823
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)				Derivatives(1)			Amounts outstanding under senior secured revolving credit facility				Net amount
	As of March 31, 2015
	Derivative assets		$	237,101			$	—			$	237,101			$	—		$	(140,962	)		$	96,139
	Derivative liabilities		—				—				—				—			—				—
			$	237,101			$	—			$	237,101			$	—		$	(140,962	)		$	96,139
	As of December 31, 2014
	Derivative assets		$	251,863			$	(232	)		$	251,631			$	—		$	(118,430	)		$	133,201
	Derivative liabilities		(309		)		232				(77		)		—			—				(77		)
			$	251,554			$	—			$	251,554			$	—		$	(118,430	)		$	133,124
	___________
	-1	Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

Asset_retirement_obligations_T

Asset retirement obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2015 and 2014.
		Three months ended March 31,
		2015			2014
	Beginning balance	$	47,424		$	55,179
	Liabilities incurred in current period	141			139
	Liabilities settled and disposed in current period	(3,030		)	(170		)
	Revisions in estimated cash flows	398			—
	Accretion expense	931			1,074
	Ending balance	45,864			56,222
	Less current portion included in accounts payable and accrued liabilities	844			1,874
		$	45,020		$	54,348

Stockbased_compensation_Tables

Stock-based compensation (Tables)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation [Abstract]
Rollforward of unvested stock-based compensation awards	A summary of our phantom stock and RSU activity during the three months ended March 31, 2015 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, 2015	$	20.18			23,179					$	9.91	569,160
	Granted	—				—					15.26		52,711
	Vested	24.48				(6,649	)		$	25	10.58		(206,332	)	$	790
	Forfeited	17.99				(4,907	)				9.62		(105,159	)
	Unvested and outstanding at March 31, 2015	$	18.64			11,623					$	10.48	310,380
	A summary of our restricted stock activity during the three months ended March 31, 2015 is presented below:
		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, 2015	$	791.52			25,834					$	292.92	38,943
	Granted	533.8				610					306.5		599
	Vested	794.4				(6,354	)		$	3,392	—		—
	Forfeited	764.16				(3,190	)				310.57		(8,719	)
	Unvested and total outstanding at March 31, 2015	$	786.3			16,900					$	288.19	30,823
Stock-based compensation cost	We recognized stock-based compensation expense as follows for the periods indicated:
			Three months ended
			March 31,
			2015				2014
	Stock-based compensation cost		$	(1,500	)		$	2,531
	Less: stock-based compensation cost capitalized		415				(962		)
	Stock-based compensation expense		$	(1,085	)		$	1,569
	Payments for stock-based compensation		$	812			$	874

Nature_of_operations_and_summa3

Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Cash and accounts receivable
Period within which joint interest accounts receivable are due	30 days
Period within which joint interest accounts receivable are past due	60 days
Components of accounts receivable
Joint interests	$21,844	$30,648
Accrued commodity sales	37,968	45,667
Derivative settlements	41,092	19,678
Other	2,014	2,738
Allowance for doubtful accounts	-337	-287
Accounts receivable, net	102,581	98,444
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held at JP Morgan Chase Bank, N. A.	$38,551

Nature_of_operations_and_summa4

Nature of operations and summary of significant accounting policies (Inventories) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Inventory, Net [Abstract]
Equipment inventory	$25,518	$24,169
Commodities	2,821	2,575
Inventory valuation allowance	-1,177	-1,187
Inventories, net	$27,162	$25,557

Nature_of_operations_and_summa5

Nature of operations and summary of significant accounting policies (Oil and Natural Gas Properties) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Capitalized costs of unproved properties excluded from amortization
Capital costs for undeveloped acreage	$188,562	$190,356
CO2 Delivery Pipelines and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	72,046	72,046
Uncompleted Wells Equipment and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	$4,501	$26,023

Nature_of_operations_and_summa6

Nature of operations and summary of significant accounting policies (Restructuring Charges) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$8,774	$0
Severance and Termination Benefits
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$6,524

Supplemental_disclosures_to_th2

Supplemental disclosures to the consolidated statements of cash flows (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Net cash provided by operating activities included:
Cash payments for interest	$19,073	$18,794
Interest capitalized	-3,462	-2,942
Cash payments for interest, net of amounts capitalized	15,611	15,852
Non-cash investing activities included:
Asset retirement obligation additions and revisions	539	139
Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities	$0	$18,629

Components_of_LongTerm_Debt_De

(Components of Long-Term Debt) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Components of long-term debt
Senior secured revolving credit facility	450,000	$347,000
Real estate mortgage notes payable	10,577	10,705
Installment notes payable	3,522	4,252
Capital lease obligations	21,245	21,837
Total long-term debt and capital lease obligations	1,735,304	1,633,802
Less current maturities	5,138	5,377
Long-term debt and capital leases, less current maturities	1,730,166	1,628,425
Mortgages | Minimum
Components of long-term debt
Stated interest rate	2.54%
Maturity date (month and year)	2021-08
Mortgages | Maximum
Components of long-term debt
Stated interest rate	5.46%
Maturity date (month and year)	2028-12
Secured Debt | Minimum
Components of long-term debt
Stated interest rate	2.85%
Maturity date (month and year)	2015-04
Secured Debt | Maximum
Components of long-term debt
Stated interest rate	5.95%
Maturity date (month and year)	2018-02
9.875% Senior Notes due 2020
Components of long-term debt
Senior Notes	295,294	295,139
Unamortized discount	4,706	4,861
9.875% Senior Notes due 2020 | Senior Notes
Components of long-term debt
Stated interest rate	9.88%
Maturity date (year)	2020
8.25% Senior Notes due 2021
Components of long-term debt
Senior Notes	400,000	400,000
8.25% Senior Notes due 2021 | Senior Notes
Components of long-term debt
Stated interest rate	8.25%
Maturity date (year)	2021
7.625% Senior Notes due 2022
Components of long-term debt
Senior Notes	554,666	554,869
Unamortized premium	4,666	$4,869
7.625% Senior Notes due 2022 | Senior Notes
Components of long-term debt
Stated interest rate	7.63%
Maturity date (year)	2022

Senior_Secured_Revolving_Credi

(Senior Secured Revolving Credit Facility) (Details) (Line of Credit, USD $)	3 Months Ended
	Mar. 31, 2015	Apr. 01, 2015
Line of Credit Facility [Line Items]
Maturity date	1-Nov-17
Proceeds from senior secured revolving credit facility	$103,000,000
Weighted average interest rate	2.20%
Borrowing base amount	650,000,000
Subsequent Event
Line of Credit Facility [Line Items]
Borrowing base amount		550,000,000
Additional borrowing capacity		$300,000,000
Minimum | Subsequent Event
Line of Credit Facility [Line Items]
Interest coverage charge ratio		2
Maximum | Subsequent Event
Line of Credit Facility [Line Items]
Ratio of consolidated secured net debt to consolidated EBITDAX covenant		2.25

Longterm_debt_Capital_Leases_D

Long-term debt (Capital Leases) (Details) (U.S. Bank National Association, Capital Lease Obligations, USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2013
U.S. Bank National Association | Capital Lease Obligations
Capital leases
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

Derivative_instruments_Outstan

Derivative instruments (Outstanding Derivatives) (Details) (USD $)	3 Months Ended			1 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014	Mar. 26, 2015
					bbl
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Investing Activities	($75,885)		$8,755
Swaps | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume MBbls	450,000
Weighted average fixed price per MMBtu	95.25
Swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	12,240,000
Weighted average fixed price per MMBtu	4.15
Swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	14,000,000
Weighted average fixed price per MMBtu	4.19
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	12,700,000
Weighted average fixed price per MMBtu	3.64
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	8,250,000
Weighted average fixed price per MMBtu	3.83
Swaps with Deferred Premium | Oil Derivative
Derivative [Line Items]
Volume MBbls	4,028,000	[1]
Average fixed price net of premiums	78.98
Swaps with Deferred Premium | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price per MMBtu	92.78	[1]
Weighted average fixed price per Bbl, purchased puts	0
Weighted average fixed price per Bbl, Average premium	13.8	[1]
Swaps with Deferred Premium | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price per Bbl, Average premium	5.54	[2]
Three-way collars | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	240,000
Weighted average fixed price per MMBtu	0
Weighted average fixed price per Bbl, sold puts	84
Weighted average fixed price per Bbl, purchased puts	92
Weighted average fixed price per Bbl, sold calls	101.01
Enhanced Swaps | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	3,720,000	[2]
Weighted average fixed price per MMBtu	92.94	[2]
Weighted average fixed price per Bbl, sold puts	80.52	[2]
Weighted average fixed price per Bbl, purchased puts	72.42
Floor price	60
Purchased Puts | Derivative Maturing in 2016
Derivative [Line Items]
Premium paid for put options on commodity derivative contracts				20,609
Average forward price	57.74
Purchased Puts | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume MBbls	3,720,000	[2]
Weighted average fixed price per Bbl, purchased puts	60	[2]
Natural gas basis protection swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	10,800,000
Weighted average fixed price per MMBtu	0.24
Natural gas basis protection swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls	8,400,000
Weighted average fixed price per MMBtu	0.36
Early Settlement
Derivative [Line Items]
Payments for (Proceeds from) Derivative Instrument, Investing Activities	$15,395
Early Settlement | Oil Derivative
Derivative [Line Items]
Volume MBbls					495,000
Early Settlement | Natural Gas Derivative
Derivative [Line Items]
Volume MBbls					12,280,000
[1]	.
[2]	Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

Derivative_instruments_Effect_

Derivative instruments (Effect of Derivative Instruments on the Consolidated Balance Sheets) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair value of derivative instruments
Derivative assets, gross	$237,101	$251,863
Netting adjustments	0	232
Current derivative assets, net	166,873	179,921
Long-term derivative assets, net	70,228	71,710
Derivative liabilities, gross	0	-309
Derivative Liability, Netting adjustments	0	-232
Current derivative liabilities, net	0	-77
Long-term derivative liabilities, net	0	0
Derivative assets (liabilities), net	237,101	251,554
Current derivative assets (liabilities), net	166,873	179,844
Long-term derivative assets (liabilities), net	70,228	71,710
Natural Gas Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	37,843	32,939
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	37,843	32,939
Natural Gas Derivative | Natural gas basis protection swaps
Fair value of derivative instruments
Derivative assets, gross	1,041	292
Derivative liabilities, gross	0	-309
Derivative assets (liabilities), net	1,041	-17
Oil Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross	19,168	23,465
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	19,168	23,465
Oil Derivative | Three-way collars
Fair value of derivative instruments
Derivative assets, gross	1,700	1,175
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	1,700	1,175
Oil Derivative | Enhanced Swaps
Fair value of derivative instruments
Derivative assets, gross	91,362	100,724
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	91,362	100,724
Oil Derivative | Purchased Puts
Fair value of derivative instruments
Derivative assets, gross	85,987	93,268
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	$85,987	$93,268

Derivative_instruments_Derivat

Derivative instruments (Derivative Settlements Outstanding) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative settlements receivable included in accounts receivable	$41,092	$19,678

Effect_of_Derivative_Instrumen

(Effect of Derivative Instruments on the Consolidated Statements of Operations) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Non-Hedge Derivative Gains (Losses) [Line Items]
Non-hedge derivative losses	$61,431	($29,199)
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	606	-5,193
(Payments on) receipts from settlement of non-hedge derivative instruments	19,027	-5,850
Three-way collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	525	-2,863
(Payments on) receipts from settlement of non-hedge derivative instruments	0	-41
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	-16,643	-10,527
(Payments on) receipts from settlement of non-hedge derivative instruments	56,949	-1,992
Natural gas basis protection swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	1,058	-1,861
(Payments on) receipts from settlement of non-hedge derivative instruments	($91)	($872)

Fair_value_measurements_Recurr

Fair value measurements (Recurring Fair Value Measurements) (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	$237,101		$251,863
Derivative liabilities, gross	0		-309
Derivative assets (liabilities), net	237,101		251,554
Derivative assets, amount offset	0		-232
Derivative liabilities, amounts offset	0		232
Derivative assets, net	237,101		251,631
Derivative liabilities, net	0		-77
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net	237,101		251,554
Derivative assets, amount offset	0	[1]	-232	[1]
Derivative liabilities, amounts offset	0	[1]	232	[1]
Derivative assets, net	237,101		251,631
Derivative liabilities, net	0		-77
Recurring Fair Value Measurements | Significant other observable inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	58,052		56,696
Derivative liabilities, gross	0		-309
Derivative assets (liabilities), net	58,052		56,387
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	179,049		195,167
Derivative liabilities, gross	0		0
Derivative assets (liabilities), net	$179,049		$195,167
[1]	Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

Fair_value_measurements_Level_

Fair value measurements (Level 3 Rollforward) (Details) (Recurring Fair Value Measurements, Significant unobservable inputs (Level 3), Derivative, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Recurring Fair Value Measurements | Significant unobservable inputs (Level 3) | Derivative
Level 3 Rollforward
Beginning balance	$195,167	$3,622
Realized and unrealized gains (losses) included in non-hedge derivative losses	40,831	-15,423
Settlements (received) paid	-56,949	2,033
Ending balance	179,049	-9,768
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$14,639	($15,324)

Fair_value_measurements_Nonrec

Fair value measurements (Nonrecurring Fair Value Measurements) (Details) (Significant unobservable inputs (Level 3), Nonrecurring fair value measurements)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Significant unobservable inputs (Level 3) | Nonrecurring fair value measurements
Nonrecurring Fair Value Measurements
Annual inflation rate	2.91%	2.95%
Credit-adjusted risk-free interest rate	12.40%	5.80%

Fair_value_measurements_Fair_V

Fair value measurements (Fair Value of Other Financial Instruments) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	$450,000	$347,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	295,294	295,139
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	400,000	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	554,666	554,869
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	450,000	347,000
Other secured long-term debt	14,099	14,957
Long-term debt	1,714,059	1,611,965
Significant other observable inputs (Level 2) | Carrying value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	295,294	295,139
Significant other observable inputs (Level 2) | Carrying value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
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
Senior Notes	554,666	554,869
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	450,000	347,000
Other secured long-term debt	14,099	14,957
Long-term debt	1,339,079	1,280,823
Significant other observable inputs (Level 2) | Estimated fair value | 9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	228,480	269,091
Significant other observable inputs (Level 2) | Estimated fair value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	278,000	270,000
Significant other observable inputs (Level 2) | Estimated fair value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	$368,500	$379,775

Fair_value_measurements_Counte

Fair value measurements (Counterparty Credit Risk) (Details) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
Counterparty Credit Risk
Derivative liabilities subject to acceleration	$0
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	8
Derivative contracts, number of counterparties subject to offset under credit facility	8

Fair_value_measurements_Deriva

Fair value measurements (Derivatives Offset in the Consolidated Balance Sheets) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value Disclosures [Abstract]
Derivative assets, gross	$237,101	$251,863
Derivative assets, amount offset	0	-232
Derivative assets	237,101	251,631
Derivative assets, not offset		0	[1]
Credit facility balance available to offset net derivative assets	-140,962	-118,430
Derivative asset, net	96,139	133,201
Derivative liabilities, gross	0	-309
Derivative liabilities, amounts offset	0	232
Derivative liabilities	0	77
Derivative liabilities, not offset		0	[1]
Derivative liability, net	0	-77
Derivative Asset (Liability), Fair Value, Gross Asset	237,101	251,554
Derivative Asset (Liability), Fair Value, Gross Liability	0	0
Derivative Asset (Liability), Net	237,101	251,554
Credit facility balance available to offset net derivative assets	-140,962	-118,430
Derivative asset (liability), net	$96,139	$133,124
[1]	Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

Asset_retirement_obligations_D

Asset retirement obligations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$47,424	$55,179
Liabilities incurred in current period	141	139
Liabilities settled and disposed in current period	-3,030	-170
Revisions in estimated cash flows	398	0
Accretion expense	931	1,074
Ending balance	45,864	56,222
Less current portion included in accounts payable and accrued liabilities	844	1,874
Asset retirement obligations	$45,020	$54,348	$43,277

Stockbased_compensation_Phanto

Stock-based compensation (Phantom Stock Plan and Restricted Stock Unit Plan) (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015
Vest date fair value
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$9,021
Phantom Stock Plan | Phantom Shares
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Days from vesting date to cash settlement	120 days
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$20.18
Granted	$0
Vested	$24.48
Forfeited	$17.99
Unvested and outstanding at end of period	$18.64
Shares
Unvested and outstanding at beginning of period (in shares)	23,179
Granted (in shares)	0
Vested (in shares)	-6,649
Forfeited (in shares)	-4,907
Unvested and outstanding at end of period (in shares)	11,623
Vest date fair value
Vest date fair value	25
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU)
Stock-Based Compensation [Line Items]
Days from vesting date to cash settlement	120 days
Maximum percentage of fair market value of the company available for share-based awards	2.00%
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$9.91
Granted	$15.26
Vested	$10.58
Forfeited	$9.62
Unvested and outstanding at end of period	$10.48
Shares
Unvested and outstanding at beginning of period (in shares)	569,160
Granted (in shares)	52,711
Vested (in shares)	-206,332
Forfeited (in shares)	-105,159
Unvested and outstanding at end of period (in shares)	310,380
Vest date fair value
Vest date fair value	790
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU) | Maximum
Stock-Based Compensation [Line Items]
Award vesting period	3 years
Phantom Stock Plan And Restricted Stock Unit Plan | Phantom Stock and RSU
Vest date fair value
Estimated fair value per share at end of period	$2.92
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding	$940

Stockbased_compensation_2010_E

Stock-based compensation (2010 Equity Incentive Plan) (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Vest date fair value
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding	$9,021
Restricted Stock | 2010 Equity Incentive Plan | Maximum | Service Vesting Conditions
Stock-Based Compensation [Line Items]
Award vesting period	5 years
Restricted Stock | 2010 Equity Incentive Plan | Common Class A
Stock-Based Compensation [Line Items]
Shares reserved for issuance under the 2010 Plan	86,301
Restricted Stock | 2010 Equity Incentive Plan | Common Class A | Service Vesting Conditions
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$791.52
Granted	$533.80
Vested	$794.40
Forfeited	$764.16
Unvested and outstanding at end of period	$786.30
Shares
Unvested and outstanding at beginning of period (in shares)	25,834
Granted (in shares)	610
Vested (in shares)	-6,354
Forfeited (in shares)	-3,190
Unvested and outstanding at end of period (in shares)	16,900
Vest date fair value
Vest date fair value	$3,392
Restricted stock used for tax withholding	1,404	1,068
Shares expected to be repurchased during the next twelve months	2,000
Estimated fair value per share at end of period	$533.80
Restricted Stock | 2010 Equity Incentive Plan | Common Class A | Performance Vested
Weighted average grant date fair value ($ per share)
Unvested and outstanding at beginning of period	$292.92
Granted	$306.50
Vested	$0
Forfeited	$310.57
Unvested and outstanding at end of period	$288.19
Shares
Unvested and outstanding at beginning of period (in shares)	38,943
Granted (in shares)	599
Vested (in shares)	0
Forfeited (in shares)	-8,719
Unvested and outstanding at end of period (in shares)	30,823

Stockbased_compensation_Stockb

Stock-based compensation (Stock-based compensation cost) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	($1,500)	$2,531
Less: stock-based compensation cost capitalized	415	-962
Stock-based compensation expense	-1,085	1,569
Payments for stock-based compensation	812	874
Stock-based compensation costs included in accrued payroll and benefits payable	4,056		4,830
Unrecognized compensation cost	$14,793
Years over which unrecognized compensation cost is expected to be recognized	2 years 3 months 18 days

Commitments_and_contingencies_

Commitments and contingencies (Details) (USD $)	3 Months Ended		1 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Jun. 07, 2011	Dec. 31, 2014
Loss Contingencies [Line Items]
Letters of credit outstanding	$874			$920
Interest paid	19,073	18,794
Pending Litigation | Minimum
Loss Contingencies [Line Items]
Damages sought			5,000
Letter of Credit
Loss Contingencies [Line Items]
Interest paid	$0	$0