Chaparral Energy (CHAP) 10-Q 16 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 16, 2015
Entity Information [Line Items]
Entity Registrant Name	Chaparral Energy, Inc.
Entity Central Index Key	1,346,980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Common Class A
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		345,289
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 ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 37,783	$ 31,492
Accounts receivable, net	77,583	98,444
Inventories, net	17,020	25,557
Prepaid expenses	2,055	4,484
Derivative instruments	142,944	179,921
Total current assets	277,385	339,898
Property and equipment—at cost, net	53,669	66,561
Oil and natural gas properties, using the full cost method:
Proved	4,049,859	3,735,817
Unevaluated (excluded from the amortization base)	98,032	288,425
Accumulated depreciation, depletion, amortization and impairment	(2,820,454)	(1,701,851)
Total oil and natural gas properties	1,327,437	2,322,391
Derivative instruments	40,766	71,710
Deferred income taxes	35,622	0
Other assets	29,019	31,256
Total assets	1,763,898	2,831,816
Current liabilities:
Accounts payable and accrued liabilities	50,608	191,957
Accrued payroll and benefits payable	10,485	21,654
Accrued interest payable	33,578	24,106
Revenue distribution payable	12,023	24,467
Current maturities of long-term debt and capital leases	4,619	5,377
Derivative instruments	39	77
Deferred income taxes	51,629	60,728
Total current liabilities	162,981	328,366
Long-term debt and capital leases, less current maturities	1,671,920	1,628,425
Stock-based compensation	1,620	3,131
Asset retirement obligations	46,518	43,277
Deferred income taxes	$ 0	$ 116,759
Commitments and contingencies (Note 9)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding	$ 0	$ 0
Additional paid in capital	430,609	429,678
Retained earnings	(549,764)	282,166
Total stockholders' equity	(119,141)	711,858
Total liabilities and stockholders' equity	1,763,898	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) - $ / shares	Sep. 30, 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 (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	10,000,000	10,000,000
Common stock, shares issued	345,336	364,896
Common stock, shares outstanding	345,336	364,896
Common Class B
Common stock, par value (in dollars per share)	$ 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 (in dollars per share)	$ 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 (in dollars per share)	$ 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 (in dollars per share)	$ 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 (in dollars per share)	$ 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 oper

Consolidated statements of operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Commodity sales	$ 74,512	$ 179,383	$ 261,801	$ 545,698
Total revenues	74,512	179,383	261,801	545,698
Costs and expenses:
Lease operating	24,881	38,915	83,921	107,650
Transportation and processing	1,902	3,162	6,246	6,012
Production taxes	2,795	7,133	11,123	21,935
Depreciation, depletion and amortization	52,027	61,527	173,694	180,631
Loss on impairment of oil and gas assets	737,758	0	955,320	0
Loss on impairment of other assets	0	0	13,311	0
General and administrative	7,389	14,820	25,843	43,199
Cost reduction initiatives	603	0	9,739	0
Total costs and expenses	827,355	125,557	1,279,197	359,427
Operating (loss) income	(752,843)	53,826	(1,017,396)	186,271
Non-operating income (expense):
Interest expense	(28,598)	(25,434)	(83,202)	(78,096)
Non-hedge derivative gains	85,415	104,413	105,266	17,218
Other income, net	108	442	2,088	1,407
Net non-operating income (expense)	56,925	79,421	24,152	(59,471)
(Loss) income before income taxes	(695,918)	133,247	(993,244)	126,800
Income tax (benefit) expense	(48,776)	49,734	(161,314)	47,315
Net (loss) income	$ (647,142)	$ 83,513	$ (831,930)	$ 79,485

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities
Net (loss) income	$ (831,930)	$ 79,485
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	173,694	180,631
Loss on impairment of assets	968,631	0
Deferred income taxes	(161,480)	46,894
Non-hedge derivative gains	(105,266)	(17,218)
Gain on sale of assets	(1,448)	(1,007)
Other	4,013	3,033
Change in assets and liabilities
Accounts receivable	16,625	(14,442)
Inventories	(3,642)	(7,287)
Prepaid expenses and other assets	2,258	998
Accounts payable and accrued liabilities	(15,012)	(906)
Revenue distribution payable	(12,444)	5,446
Stock-based compensation	(4,355)	3,504
Net cash provided by operating activities	29,644	279,131
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(267,203)	(499,255)
Proceeds from asset dispositions	29,251	258,578
Settlement of non-hedge derivative instruments	173,149	(25,038)
Net cash used in investing activities	(64,803)	(265,715)
Cash flows from financing activities
Proceeds from long-term debt	120,000	186,999
Repayment of long-term debt	(75,354)	(227,572)
Principal payments under capital lease obligations	(1,792)	(1,726)
Payment of other financing fees	(1,404)	0
Net cash provided by (used in) financing activities	41,450	(42,299)
Net increase (decrease) in cash and cash equivalents	6,291	(28,883)
Cash and cash equivalents at beginning of period	31,492	48,595
Cash and cash equivalents at end of period	$ 37,783	$ 19,712

Nature of operations and summar

Nature of operations and summary of significant accounting policies	9 Months Ended
	Sep. 30, 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 September 30, 2015 , and for the three and nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 2015 , cash with a recorded balance totaling $36,124 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. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following at September 30, 2015 and December 31, 2014 : September 30, December 31, Joint interests $ 10,928 $ 30,648 Accrued commodity sales 28,060 45,667 Derivative settlements 37,388 19,678 Other 1,694 2,738 Allowance for doubtful accounts (487 ) (287 ) $ 77,583 $ 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. We recorded a lower of cost or market adjustment of nil and $7,296 on our equipment inventory for the three and nine months ended September 30, 2015 , respectively. The adjustment, recorded during the second quarter of 2015, was to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity has decreased in the current low commodity price environment. The adjustment is reflected in “Loss on impairment of other assets” in our consolidated statements of operations.We did not record any significant inventory adjustments in the prior year periods. Inventories at September 30, 2015 and December 31, 2014 consisted of the following: September 30, December 31, Equipment inventory $ 23,050 $ 24,169 Commodities 1,839 2,575 Inventory valuation allowance (7,869 ) (1,187 ) $ 17,020 $ 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 September 30, 2015 , include $95,325 of capital costs incurred for undeveloped acreage and $2,707 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 CO 2 delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination. Our work-in-progress balance at September 30, 2015 no longer includes amounts related to the construction of CO 2 delivery pipelines and facilities as those have been reclassified to the full-cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the development of all remaining phases at our North Burbank Unit. 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 September 30, 2015 were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. Due to the substantial decline of commodity prices that began in late 2014 and which remained low through September 30, 2015 , the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the three and nine months ended September 30, 2015 of $737,758 and $955,320 , respectively. Further write-downs are expected to occur in significant amounts if prices remain at their depressed levels. The amount of any future impairment is generally 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. Impairment of long-lived assets Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell. We recorded impairment losses of nil and $6,015 related to four drilling rigs not currently in use for the three and nine months ended September 30, 2015 . One of the rigs was last deployed in January 2015 while the remaining three have been stacked for two to three years. As a result of the recent deterioration in commodity prices and drilling activity, the value of such equipment has declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value during the second quarter of 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. We had previously recorded $3,490 and $1,500 of impairment related to these rigs during the years ended December 31, 2013 and 2012, respectively. 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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy. 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 assets 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. Income Taxes For 2015, our annual estimated effective tax rate is forecasted to be a benefit of 28.7% , exclusive of discrete items. We expect to incur both a book and tax loss in year 2015. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the quarter ended September 30, 2015, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and state income tax apportionment. In forecasting the 2015 annual estimated effective tax rate, we believe that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2015. We reached this conclusion considering several factors such as: (i) projected future tax losses, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in our balance sheet (which are primarily related to derivative instruments). At this time, the estimated valuation allowance to be recorded in 2015 would be approximately $225,000 including $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014. 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 $9,739 of expenses for cost reduction initiatives for the nine months ended September 30, 2015, are $ 6,524 , $347 and $596 recorded during the first, second and third quarters of 2015, respectively, for one-time severance and termination benefits in connection with our reduction in force that we began implementing 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 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. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, 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. Adoption of this guidance will only affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. Recent guidance issued in August 2015 clarifies the issue by allowing an entity to defer and present debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. As our current policy is consistent with the recent guidance, the update regarding debt issuance costs for line-of-credit arrangements will not impact our financial statements or results of operations. In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public business entities, 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.

Supplemental disclosures to the

Supplemental disclosures to the consolidated statements of cash flows	9 Months Ended
	Sep. 30, 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: Nine months ended September 30, 2015 2014 Net cash provided by operating activities included: Cash payments for interest $ 77,437 $ 74,446 Interest capitalized (8,115 ) (9,957 ) Cash payments for interest, net of amounts capitalized $ 69,322 $ 64,489 Cash payments for income taxes $ 639 $ 591 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 3,637 $ 7,118 Change in accrued oil and gas capital expenditures $ (116,237 ) $ 22,458

Acquisitions and divestitures

Acquisitions and divestitures	9 Months Ended
	Sep. 30, 2015
Acquisitions and Divestitures [Abstract]
Acquisitions and divestitures	Acquisitions and divestitures During the nine months ended September 30, 2015 we sold various non-core oil and gas properties for total proceeds of $26,868 . The properties sold include acreage in various counties in South-Central Oklahoma in the SCOOP play (“South-Central Oklahoma Oil Province”) and oil and gas properties in Osage County. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

Long-term debt

Long-term debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long-term debt	Long-term debt As of the dates indicated, long-term debt consisted of the following: September 30, 2015 December 31, 2014 9.875% Senior Notes due 2020, net of discount of $4,382 and $4,861, respectively $ 295,618 $ 295,139 8.25% Senior Notes due 2021 400,000 400,000 7.625% Senior Notes due 2022, including premium of $4,272 and $4,869, respectively 554,272 554,869 Senior secured revolving credit facility 394,000 347,000 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 10,315 10,705 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due October 2015 through February 2018; collateralized by automobiles, machinery and equipment 2,289 4,252 Capital lease obligations 20,045 21,837 1,676,539 1,633,802 Less current maturities 4,619 5,377 $ 1,671,920 $ 1,628,425 Senior Notes The senior notes, which, as of September 30, 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 nine months ended September 30, 2015, we had additional net borrowings of $47,000 on our senior secured revolving credit facility. As of September 30, 2015 , the weighted average interest rate was 2.3% 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 a result of that semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015. Our semiannual borrowing base redetermination, which was effective on October 29, 2015, reaffirmed our borrowing base at $550,000 . In connection with the Fifteenth Amendment, effective April 1, 2015, the Consolidated Net Debt to Consolidated EBITDAX covenant previously required by our senior secured revolving credit facility was 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 incurred $1,404 in fees associated with the Fifteenth Amendment. We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 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	9 Months Ended
	Sep. 30, 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, collars, put options, and basis protection swaps. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production. From time to time, we may enter into derivative contracts that are not costless but instead require payment of a premium such as purchased puts, collars and three-way collars. The cash premium can be paid at the time the contracts are initiated or deferred until the contracts settle. Payment of deferred premiums at the contract settlement date reduces the proceeds to be received upon settlement of the contracts. The fair value of our derivative contracts are reported net of any deferred premiums that are payable under the contracts. 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. On a purchased put option, 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 collars. 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 September 30, 2015 : Weighted average fixed price per Bbl Period and type of contract Volume Swaps Sold puts Purchased puts Sold calls Average deferred premium 2015 Swaps (1) 630 $ 91.38 $ — $ — $ — $ 13.80 Collars (1) 130 $ — $ — $ 47.50 $ 57.50 $ 1.71 Purchased puts (1) 695 $ — $ — $ 43.05 $ — $ 2.96 2016 Three-way collars 240 $ — $ 84.00 $ 92.00 $ 101.01 $ — Three-way collars (1) 480 $ — $ 40.00 $ 52.50 $ 72.50 $ 2.95 Enhanced swaps (2) 3,720 $ 92.94 $ 80.52 $ — $ — $ — Purchased puts (2) 3,720 $ — $ — $ 60.00 $ — $ — 2017 Three-way collars (1) 480 $ — $ 42.50 $ 55.00 $ 80.00 $ 2.78 ___________ (1) These contracts include deferred premiums that are payable upon settlement. (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 $48.70 for 2016 as of September 30, 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 September 30, 2015 : Period and type of contract Volume Weighted 2015 Natural gas swaps 3,940 $ 4.24 Natural gas basis protection swaps 3,600 $ 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 for the nine months ended September 30, 2015 . Prior to July 2015, our derivative portfolio included certain outstanding swaps, scheduled to mature between September and December 2015, covering 1,100,000 barrels of production. Net of deferred premiums of $12,424 , the effective hedged price provided by these swaps was $82.34 per barrel. During the third quarter of 2015, we entered into offset positions on these swaps thereby locking in proceeds based on the difference between the contract price of the initial swaps and the contract price of the offset swaps, which we will receive as the contracts settle. Based on the September through December 2015 average NYMEX strip price of $45.70 per barrel at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the 1,100,000 barrels of production, would be $82.68 per barrel. Any difference between settlement prices at contract maturity and the preceding average NYMEX price of $45.70 per barrel would result in a dollar for dollar impact on the realized price we receive. At September 30, 2015, 275,000 barrels of the locked-in swaps had matured for which net proceeds of $10,196 are to be received. Based on the October through December 2015 average NYMEX strip price of $45.77 , at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the remaining 825,000 barrels of production, will yield an effective price of $82.72 . The 825,000 barrels of remaining locked-in swaps are not reflected in the derivatives outstanding table above as the anticipated proceeds no longer vary according to changes in crude oil pricing. However, the anticipated proceeds from the remaining locked-in swaps are reflected in the derivative asset and liability values disclosed in the table 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 6 — 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 September 30, 2015 As of December 31, 2014 Assets Liabilities Net value Assets Liabilities Net value Natural gas swaps $ 39,554 $ — $ 39,554 $ 32,939 $ — $ 32,939 Oil swaps 9,386 (1,810 ) 7,576 23,465 — 23,465 Oil collars (2) 3,483 — 3,483 1,175 — 1,175 Oil enhanced swaps 60,755 — 60,755 100,724 — 100,724 Oil purchased and sold puts 74,386 (924 ) 73,462 93,268 — 93,268 Natural gas basis differential swaps — (1,159 ) (1,159 ) 292 (309 ) (17 ) Total derivative instruments 187,564 (3,893 ) 183,671 251,863 (309 ) 251,554 Less: Netting adjustments (1) 3,854 (3,854 ) — 232 (232 ) — Current portion asset (liability) 142,944 (39 ) 142,905 179,921 (77 ) 179,844 $ 40,766 $ — $ 40,766 $ 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. (2) Includes collars and 3-way collars. Derivative settlements outstanding at September 30, 2015 and December 31, 2014 were as follows: September 30, December 31, Derivative settlements receivable included in accounts receivable $ 37,388 $ 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 in the consolidated statements of operations. Non-hedge derivative gains in the consolidated statements of operations are comprised of the following: Three months ended Nine months ended September 30, September 30, 2015 2014 2015 2014 Change in fair value of commodity price swaps $ 6,583 $ 20,039 $ (9,274 ) $ 16,794 Change in fair value of collars 1,803 6,870 2,307 106 Change in fair value of enhanced swaps and put options 23,590 80,551 (59,775 ) 27,521 Change in fair value of natural gas basis differential contracts (1,035 ) 9 (1,141 ) (2,165 ) Receipts from (payments on) settlement of commodity price swaps 12,829 (1,030 ) 43,806 (12,653 ) Receipts from (payments on) settlement of collars 42 (77 ) 42 (1,338 ) Receipts from (payments on) settlement of enhanced swaps and put options 41,667 (1,664 ) 129,245 (10,657 ) (Payments on) receipts from settlement of natural gas basis differential contracts (64 ) (285 ) 56 (390 ) $ 85,415 $ 104,413 $ 105,266 $ 17,218

Fair value measurements

Fair value measurements	9 Months Ended
	Sep. 30, 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 5 — Derivative instruments ). We have no Level 1 assets or liabilities as of September 30, 2015 or December 31, 2014 . Our derivative contracts classified as Level 2 as of September 30, 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 September 30, 2015 and December 31, 2014 , our derivative contracts classified as Level 3 consisted of collars, 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 September 30, 2015 As of December 31, 2014 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 48,940 $ (2,969 ) $ 45,971 $ 56,696 $ (309 ) $ 56,387 Significant unobservable inputs (Level 3) 138,624 (924 ) 137,700 195,167 — 195,167 Netting adjustments (1) (3,854 ) 3,854 — (232 ) 232 — $ 183,710 $ (39 ) $ 183,671 $ 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 nine months ended September 30, 2015 and 2014 were: Nine months ended September 30, Net derivative assets (liabilities) 2015 2014 Beginning balance $ 195,167 $ 3,622 Realized and unrealized gains (losses) included in non-hedge derivative gains (losses) 4,660 15,632 Purchases — 1,220 Settlements (received) paid (62,127 ) 11,995 Ending balance $ 137,700 $ 32,469 Losses relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period $ 45,835 $ 24,156 Nonrecurring fair value measurements Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first nine months of 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95% , respectively, and discounted using our weighted average credit-adjusted risk-free interest rate of 13.45% and 6.60% , respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 7 — Asset retirement obligations for additional information regarding our asset retirement obligations. Impairment of long-lived assets. As discussed in Note 1 — Nature of operations and summary of significant accounting policies , we recorded an impairment on four of our stacked drilling rigs during the second quarter of 2015. The estimated fair value related to the impairment assessment for our four drilling rigs no longer in service was primarily based on internal and external estimates and, therefore, is classified within Level 3 of the fair value hierarchy. 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 September 30, 2015 and December 31, 2014 were as follows: September 30, 2015 December 31, 2014 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 295,618 $ 97,500 $ 295,139 $ 269,091 8.25% Senior Notes due 2021 400,000 122,000 400,000 270,000 7.625% Senior Notes due 2022 554,272 154,000 554,869 379,775 Senior secured revolving credit facility 394,000 394,000 347,000 347,000 Other secured long-term debt 12,604 12,604 14,957 14,957 $ 1,656,494 $ 780,104 $ 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 September 30, 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 September 30, 2015 Derivative assets $ 187,564 $ (3,854 ) $ 183,710 $ — $ (114,282 ) $ 69,428 Derivative liabilities (3,893 ) 3,854 (39 ) — — (39 ) $ 183,671 $ — $ 183,671 $ — $ (114,282 ) $ 69,389 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 $3,893 at September 30, 2015 .

Asset retirement obligations

Asset retirement obligations	9 Months Ended
	Sep. 30, 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 nine months ended September 30, 2015 and 2014 . Nine months ended September 30, 2015 2014 Beginning balance $ 47,424 $ 55,179 Liabilities incurred in current period 1,852 4,844 Liabilities settled and disposed in current period (4,886 ) (16,807 ) Revisions in estimated cash flows 1,785 2,274 Accretion expense 2,727 2,991 Ending balance 48,902 48,481 Less current portion included in accounts payable and accrued liabilities 2,384 4,997 $ 46,518 $ 43,484 See Note 6 — Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

Stock-based compensation

Stock-based compensation	9 Months Ended
	Sep. 30, 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 nine months ended September 30, 2015 is presented in the following table: Phantom Plan RSU Plan Weighted average grant date fair value Phantom shares Vest date fair value Weighted average grant date fair value Restricted Stock Units Vest date fair value ($ per share) ($ per share) Unvested and outstanding at January 1, 2015 $ 20.18 23,179 $ 9.91 569,160 Granted $ — — $ 14.88 59,571 Vested $ 24.48 (6,456 ) $ 25 $ 10.73 (216,941 ) $ 857 Forfeited $ 18.34 (6,032 ) $ 9.62 (133,132 ) Unvested and outstanding at September 30, 2015 $ 18.61 10,691 $ 10.48 278,658 Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per phantom share and RSU as of September 30, 2015 is $0.00 . The weighted average period until all remaining phantom shares and RSUs vest is 1.3 years . 2015 Cash Incentive Plan We adopted the Long-Term Cash Incentive Plan (The “2015 Cash LTIP”) on August 7, 2015. The 2015 Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four -year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We awarded $3,297 of cash incentive awards in September 2015. 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 nine months ended September 30, 2015 is presented below: Time Vested Performance Vested Weighted average grant date fair value Restricted shares Vest date fair value Weighted average grant date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2015 $ 791.52 25,834 $ 292.92 38,943 Granted $ 533.80 610 $ 113.90 599 Vested $ 778.81 (8,325 ) $ 4,444 $ — — Forfeited $ 774.21 (3,997 ) $ 323.53 (11,094 ) Unvested and outstanding at September 30, 2015 $ 792.78 14,122 $ 278.97 28,448 During the nine months ended September 30, 2015 and 2014 , we repurchased and canceled 5,678 and 1,810 vested shares respectively, 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 $373.10 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $5,269 as of September 30, 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 Nine months ended September 30, September 30, 2015 2014 2015 2014 Stock-based compensation cost $ (581 ) $ 2,309 $ (143 ) $ 9,026 Less: stock-based compensation cost capitalized (49 ) (289 ) (352 ) (2,735 ) Stock-based compensation expense $ (630 ) $ 2,020 $ (495 ) $ 6,291 Payments for stock-based compensation $ 333 $ 699 $ 3,977 $ 2,787 Our stock-based compensation expense for the nine months ended September 30, 2015 includes a credit recorded in the first quarter due to forfeitures resulting from our workforce reduction in February 2015 and a credit recorded during the third quarter due to lower valuations of our liability-based awards. As of September 30, 2015 and December 31, 2014 , accrued payroll and benefits payable included $1,384 and $4,830 , respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $7,134 is expected to be recognized over a weighted average period of 1.8 years .

Commitments and contingencies

Commitments and contingencies	9 Months Ended
	Sep. 30, 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 September 30, 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 nine months ended September 30, 2015 or 2014 . Litigation and Claims Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, 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. The plaintiffs filed their motion for class certification on Tuesday, October 13, 2015. The plaintiffs also moved for partial summary judgment, asking the court to determine, as a matter of law, that natural gas is not marketable until it is in a condition and location to be transported in an interstate pipeline and other dispositive issues. The Company is preparing its response to both motions. 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 Plaintiff’s 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 our 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 Plaintiff’s 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. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Donelson Case will have on our 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 properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the Donelson 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 CO 2 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 CO 2 , drilling rig services, pipe and equipment. In September 2015, we entered into an interim financing agreement with U.S. Bank for an additional CO 2 recycle compressor for our EOR facilities. If we do not enter into a lease once the compressor has been manufactured, we will owe U.S. Bank most of the cost incurred by U.S. Bank for the compressor. Other than additional debt borrowings during the nine months ended September 30, 2015 , and our obligation under the interim financing agreement discussed above, there were no material changes to our contractual commitments since December 31, 2014 .

Nature of operations and summ15

Nature of operations and summary of significant accounting policies (Policies)	9 Months Ended
	Sep. 30, 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 September 30, 2015 , and for the three and nine months ended September 30, 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 and nine months ended September 30, 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. When we recover amounts that were previously written off, those amounts 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 September 30, 2015 , include $95,325 of capital costs incurred for undeveloped acreage and $2,707 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 CO 2 delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination. Our work-in-progress balance at September 30, 2015 no longer includes amounts related to the construction of CO 2 delivery pipelines and facilities as those have been reclassified to the full-cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the development of all remaining phases at our North Burbank Unit. 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 September 30, 2015 were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. Due to the substantial decline of commodity prices that began in late 2014 and which remained low through September 30, 2015 , the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the three and nine months ended September 30, 2015 of $737,758 and $955,320 , respectively. Further write-downs are expected to occur in significant amounts if prices remain at their depressed levels. The amount of any future impairment is generally 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.
Impairment of long-lived assets	Impairment of long-lived assets Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.
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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy. 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 assets 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.
Income taxes	Income Taxes For 2015, our annual estimated effective tax rate is forecasted to be a benefit of 28.7% , exclusive of discrete items. We expect to incur both a book and tax loss in year 2015. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the quarter ended September 30, 2015, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and state income tax apportionment. In forecasting the 2015 annual estimated effective tax rate, we believe that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2015. We reached this conclusion considering several factors such as: (i) projected future tax losses, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in our balance sheet (which are primarily related to derivative instruments). At this time, the estimated valuation allowance to be recorded in 2015 would be approximately $225,000 including $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014.
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 $9,739 of expenses for cost reduction initiatives for the nine months ended September 30, 2015, are $ 6,524 , $347 and $596 recorded during the first, second and third quarters of 2015, respectively, for one-time severance and termination benefits in connection with our reduction in force that we began implementing 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 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. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, 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. Adoption of this guidance will only affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. Recent guidance issued in August 2015 clarifies the issue by allowing an entity to defer and present debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. As our current policy is consistent with the recent guidance, the update regarding debt issuance costs for line-of-credit arrangements will not impact our financial statements or results of operations. In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public business entities, 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.

Nature of operations and summ16

Nature of operations and summary of significant accounting policies (Tables)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Components of accounts receivable	Accounts receivable consisted of the following at September 30, 2015 and December 31, 2014 : September 30, December 31, Joint interests $ 10,928 $ 30,648 Accrued commodity sales 28,060 45,667 Derivative settlements 37,388 19,678 Other 1,694 2,738 Allowance for doubtful accounts (487 ) (287 ) $ 77,583 $ 98,444
Components of inventory	Inventories at September 30, 2015 and December 31, 2014 consisted of the following: September 30, December 31, Equipment inventory $ 23,050 $ 24,169 Commodities 1,839 2,575 Inventory valuation allowance (7,869 ) (1,187 ) $ 17,020 $ 25,557

Supplemental disclosures to t17

Supplemental disclosures to the consolidated statements of cash flows (Tables)	9 Months Ended
	Sep. 30, 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: Nine months ended September 30, 2015 2014 Net cash provided by operating activities included: Cash payments for interest $ 77,437 $ 74,446 Interest capitalized (8,115 ) (9,957 ) Cash payments for interest, net of amounts capitalized $ 69,322 $ 64,489 Cash payments for income taxes $ 639 $ 591 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 3,637 $ 7,118 Change in accrued oil and gas capital expenditures $ (116,237 ) $ 22,458

Long-term debt (Tables)

Long-term debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Components of long-term debt	As of the dates indicated, long-term debt consisted of the following: September 30, 2015 December 31, 2014 9.875% Senior Notes due 2020, net of discount of $4,382 and $4,861, respectively $ 295,618 $ 295,139 8.25% Senior Notes due 2021 400,000 400,000 7.625% Senior Notes due 2022, including premium of $4,272 and $4,869, respectively 554,272 554,869 Senior secured revolving credit facility 394,000 347,000 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 10,315 10,705 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due October 2015 through February 2018; collateralized by automobiles, machinery and equipment 2,289 4,252 Capital lease obligations 20,045 21,837 1,676,539 1,633,802 Less current maturities 4,619 5,377 $ 1,671,920 $ 1,628,425

Derivative instruments (Tables)

Derivative instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Outstanding derivative instruments	The following table summarizes our crude oil derivatives outstanding as of September 30, 2015 : Weighted average fixed price per Bbl Period and type of contract Volume Swaps Sold puts Purchased puts Sold calls Average deferred premium 2015 Swaps (1) 630 $ 91.38 $ — $ — $ — $ 13.80 Collars (1) 130 $ — $ — $ 47.50 $ 57.50 $ 1.71 Purchased puts (1) 695 $ — $ — $ 43.05 $ — $ 2.96 2016 Three-way collars 240 $ — $ 84.00 $ 92.00 $ 101.01 $ — Three-way collars (1) 480 $ — $ 40.00 $ 52.50 $ 72.50 $ 2.95 Enhanced swaps (2) 3,720 $ 92.94 $ 80.52 $ — $ — $ — Purchased puts (2) 3,720 $ — $ — $ 60.00 $ — $ — 2017 Three-way collars (1) 480 $ — $ 42.50 $ 55.00 $ 80.00 $ 2.78 ___________ (1) These contracts include deferred premiums that are payable upon settlement. (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 $48.70 for 2016 as of September 30, 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 September 30, 2015 : Period and type of contract Volume Weighted 2015 Natural gas swaps 3,940 $ 4.24 Natural gas basis protection swaps 3,600 $ 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 September 30, 2015 As of December 31, 2014 Assets Liabilities Net value Assets Liabilities Net value Natural gas swaps $ 39,554 $ — $ 39,554 $ 32,939 $ — $ 32,939 Oil swaps 9,386 (1,810 ) 7,576 23,465 — 23,465 Oil collars (2) 3,483 — 3,483 1,175 — 1,175 Oil enhanced swaps 60,755 — 60,755 100,724 — 100,724 Oil purchased and sold puts 74,386 (924 ) 73,462 93,268 — 93,268 Natural gas basis differential swaps — (1,159 ) (1,159 ) 292 (309 ) (17 ) Total derivative instruments 187,564 (3,893 ) 183,671 251,863 (309 ) 251,554 Less: Netting adjustments (1) 3,854 (3,854 ) — 232 (232 ) — Current portion asset (liability) 142,944 (39 ) 142,905 179,921 (77 ) 179,844 $ 40,766 $ — $ 40,766 $ 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. (2) Includes collars and 3-way collars.
Derivative settlements outstanding	Derivative settlements outstanding at September 30, 2015 and December 31, 2014 were as follows: September 30, December 31, Derivative settlements receivable included in accounts receivable $ 37,388 $ 19,678
Non-hedge derivative gains (losses) in the consolidated statements of operations	Non-hedge derivative gains in the consolidated statements of operations are comprised of the following: Three months ended Nine months ended September 30, September 30, 2015 2014 2015 2014 Change in fair value of commodity price swaps $ 6,583 $ 20,039 $ (9,274 ) $ 16,794 Change in fair value of collars 1,803 6,870 2,307 106 Change in fair value of enhanced swaps and put options 23,590 80,551 (59,775 ) 27,521 Change in fair value of natural gas basis differential contracts (1,035 ) 9 (1,141 ) (2,165 ) Receipts from (payments on) settlement of commodity price swaps 12,829 (1,030 ) 43,806 (12,653 ) Receipts from (payments on) settlement of collars 42 (77 ) 42 (1,338 ) Receipts from (payments on) settlement of enhanced swaps and put options 41,667 (1,664 ) 129,245 (10,657 ) (Payments on) receipts from settlement of natural gas basis differential contracts (64 ) (285 ) 56 (390 ) $ 85,415 $ 104,413 $ 105,266 $ 17,218

Fair value measurements (Tables

Fair value measurements (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2015 As of December 31, 2014 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 48,940 $ (2,969 ) $ 45,971 $ 56,696 $ (309 ) $ 56,387 Significant unobservable inputs (Level 3) 138,624 (924 ) 137,700 195,167 — 195,167 Netting adjustments (1) (3,854 ) 3,854 — (232 ) 232 — $ 183,710 $ (39 ) $ 183,671 $ 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 nine months ended September 30, 2015 and 2014 were: Nine months ended September 30, Net derivative assets (liabilities) 2015 2014 Beginning balance $ 195,167 $ 3,622 Realized and unrealized gains (losses) included in non-hedge derivative gains (losses) 4,660 15,632 Purchases — 1,220 Settlements (received) paid (62,127 ) 11,995 Ending balance $ 137,700 $ 32,469 Losses relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period $ 45,835 $ 24,156
Fair value of other financial instruments	The carrying value and estimated fair value of our long-term debt at September 30, 2015 and December 31, 2014 were as follows: September 30, 2015 December 31, 2014 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 295,618 $ 97,500 $ 295,139 $ 269,091 8.25% Senior Notes due 2021 400,000 122,000 400,000 270,000 7.625% Senior Notes due 2022 554,272 154,000 554,869 379,775 Senior secured revolving credit facility 394,000 394,000 347,000 347,000 Other secured long-term debt 12,604 12,604 14,957 14,957 $ 1,656,494 $ 780,104 $ 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 September 30, 2015 Derivative assets $ 187,564 $ (3,854 ) $ 183,710 $ — $ (114,282 ) $ 69,428 Derivative liabilities (3,893 ) 3,854 (39 ) — — (39 ) $ 183,671 $ — $ 183,671 $ — $ (114,282 ) $ 69,389 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)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2015 and 2014 . Nine months ended September 30, 2015 2014 Beginning balance $ 47,424 $ 55,179 Liabilities incurred in current period 1,852 4,844 Liabilities settled and disposed in current period (4,886 ) (16,807 ) Revisions in estimated cash flows 1,785 2,274 Accretion expense 2,727 2,991 Ending balance 48,902 48,481 Less current portion included in accounts payable and accrued liabilities 2,384 4,997 $ 46,518 $ 43,484

Stock-based compensation (Table

Stock-based compensation (Tables)	9 Months Ended
	Sep. 30, 2015
Share-based Compensation [Abstract]
Rollforward of unvested stock-based compensation awards	A summary of our phantom stock and RSU activity during the nine months ended September 30, 2015 is presented in the following table: Phantom Plan RSU Plan Weighted average grant date fair value Phantom shares Vest date fair value Weighted average grant date fair value Restricted Stock Units Vest date fair value ($ per share) ($ per share) Unvested and outstanding at January 1, 2015 $ 20.18 23,179 $ 9.91 569,160 Granted $ — — $ 14.88 59,571 Vested $ 24.48 (6,456 ) $ 25 $ 10.73 (216,941 ) $ 857 Forfeited $ 18.34 (6,032 ) $ 9.62 (133,132 ) Unvested and outstanding at September 30, 2015 $ 18.61 10,691 $ 10.48 278,658 A summary of our restricted stock activity during the nine months ended September 30, 2015 is presented below: Time Vested Performance Vested Weighted average grant date fair value Restricted shares Vest date fair value Weighted average grant date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2015 $ 791.52 25,834 $ 292.92 38,943 Granted $ 533.80 610 $ 113.90 599 Vested $ 778.81 (8,325 ) $ 4,444 $ — — Forfeited $ 774.21 (3,997 ) $ 323.53 (11,094 ) Unvested and outstanding at September 30, 2015 $ 792.78 14,122 $ 278.97 28,448
Stock-based compensation cost	We recognized stock-based compensation expense as follows for the periods indicated: Three months ended Nine months ended September 30, September 30, 2015 2014 2015 2014 Stock-based compensation cost $ (581 ) $ 2,309 $ (143 ) $ 9,026 Less: stock-based compensation cost capitalized (49 ) (289 ) (352 ) (2,735 ) Stock-based compensation expense $ (630 ) $ 2,020 $ (495 ) $ 6,291 Payments for stock-based compensation $ 333 $ 699 $ 3,977 $ 2,787

Nature of operations and summ23

Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 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	$ 10,928	$ 30,648
Accrued commodity sales	28,060	45,667
Derivative settlements	37,388	19,678
Other	1,694	2,738
Allowance for doubtful accounts	(487)	(287)
Accounts receivable, net	77,583	$ 98,444
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held at JP Morgan Chase Bank, N. A.	$ 36,124

Nature of operations and summ24

Nature of operations and summary of significant accounting policies (Inventories) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Inventory Adjustments [Abstract]
Equipment inventory	$ 23,050	$ 23,050	$ 24,169
Commodities	1,839	1,839	2,575
Inventory valuation allowance	(7,869)	(7,869)	(1,187)
Inventories, net	17,020	17,020	$ 25,557
Loss on impairment of other assets
Inventory [Line Items]
Inventory write-down	$ 0	$ 7,296

Nature of operations and summ25

Nature of operations and summary of significant accounting policies (Oil and Natural Gas Properties) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Capitalized costs of unproved properties excluded from amortization
Capital costs for undeveloped acreage	$ 95,325	$ 190,356
CO2 Delivery Pipelines and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization		72,046
Uncompleted Wells Equipment and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	$ 2,707	$ 26,023

Nature of operations and summ26

Nature of operations and summary of significant accounting policies (Asset Impairment) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Loss on impairment of oil and gas assets	$ 737,758	$ 0	$ 955,320	$ 0
Loss on impairment of other assets	$ 0		$ 6,015		$ 3,490	$ 1,500

Nature of operations and summ27

Nature of operations and summary of significant accounting policies (Income Taxes) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Federal statutory income tax rate	35.00%
Estimated valuation allowance	$ 225,000
Discrete item associated with Federal and State NOL carryforwards	$ 126,000
Scenario, Forecast
Income Tax Contingency [Line Items]
Annual effective tax tax forecast		28.70%

Nature of operations and summ28

Nature of operations and summary of significant accounting policies (Cost Reduction Intiatives) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 603			$ 0	$ 9,739	$ 0
Severance and Termination Benefits
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 596	$ 347	$ 6,524

Supplemental disclosures to t29

Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Net cash provided by operating activities included:
Cash payments for interest	$ 77,437	$ 74,446
Interest capitalized	(8,115)	(9,957)
Cash payments for interest, net of amounts capitalized	69,322	64,489
Cash payments for income taxes	639	591
Non-cash investing activities included:
Asset retirement obligation additions and revisions	3,637	7,118
Change in accrued oil and gas capital expenditures	$ (116,237)	$ 22,458

Acquisitions and divestitures (

Acquisitions and divestitures (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)
SCOOP play
Long Lived Assets Held-for-sale [Line Items]
Proceeds from sale of various non-core oil and gas properties	$ 26,868

Long-term debt (Components of L

Long-term debt (Components of Long-Term Debt) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Components of long-term debt
Senior secured revolving credit facility	$ 394,000	$ 347,000
Real estate mortgage notes payable	10,315	10,705
Installment notes payable	2,289	4,252
Capital lease obligations	20,045	21,837
Total long-term debt and capital lease obligations	1,676,539	1,633,802
Less current maturities	4,619	5,377
Long-term debt and capital leases, less current maturities	$ 1,671,920	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)	2015-10
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	$ 295,618	295,139
Unamortized discount	$ 4,382	4,861
9.875% Senior Notes due 2020 | Senior Notes
Components of long-term debt
Stated interest rate	9.875%
Maturity date (year)	2,020
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)	2,021
7.625% Senior Notes due 2022
Components of long-term debt
Senior Notes	$ 554,272	554,869
Unamortized premium	$ 4,272	$ 4,869
7.625% Senior Notes due 2022 | Senior Notes
Components of long-term debt
Stated interest rate	7.625%
Maturity date (year)	2,022

Long-term debt (Senior Secured

Long-term debt (Senior Secured Revolving Credit Facility) (Details)	9 Months Ended
	Sep. 30, 2015USD ($)Quarters	Oct. 29, 2015USD ($)	Apr. 01, 2015USD ($)	Mar. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Number of consecutive quarters | Quarters	4
Line of Credit
Line of Credit Facility [Line Items]
Maturity date	Nov. 1, 2017
Proceeds from senior secured revolving credit facility	$ 47,000,000
Weighted average interest rate	2.30%
Borrowing base amount			$ 550,000,000	$ 650,000,000
Additional borrowing capacity	$ 300,000,000
Debt related fees	$ 1,404,000
Line of Credit | Minimum
Line of Credit Facility [Line Items]
Interest coverage charge ratio	2
Line of Credit | Maximum
Line of Credit Facility [Line Items]
Ratio of consolidated secured net debt to consolidated EBITDAX covenant	2.25
Subsequent Event | Line of Credit
Line of Credit Facility [Line Items]
Borrowing base amount		$ 550,000,000

Long-term debt (Capital Leases)

Long-term debt (Capital Leases) (Details) - U.S. Bank National Association - Capital Lease Obligations - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2013
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) MMBTU in Thousands, $ in Thousands		1 Months Ended			3 Months Ended				9 Months Ended
		Sep. 30, 2015USD ($)MMBTUbbl$ / contract$ / bbl$ / MMBTU		Dec. 31, 2014USD ($)	Sep. 30, 2015USD ($)MMBTUbbl$ / contract$ / bbl$ / MMBTU		Mar. 31, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)MMBTUbbl$ / contract$ / bbl$ / MMBTU		Sep. 30, 2014USD ($)	Aug. 31, 2015bbl$ / bbl	Jun. 30, 2015USD ($)bbl$ / bbl	Mar. 26, 2015MMBTUbbl
Derivative Maturing in 2015 | NYMEX Strip Price, September through December
Derivative [Line Items]
Average forward price (usd per barrel)		45.70			45.70				45.70
Derivative Maturing in 2015 | NYMEX Strip Price, October through December
Derivative [Line Items]
Average forward price (usd per barrel)		45.77			45.77				45.77
Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price		72.42			72.42				72.42
Derivative Maturing in 2016 | NYMEX Strip Price
Derivative [Line Items]
Average forward price (usd per barrel)		48.70			48.70				48.70
Swaps
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $					$ (12,829)			$ 1,030	$ (43,806)		$ 12,653
Swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		3,940			3,940				3,940
Weighted average fixed price | $ / MMBTU		4.24			4.24				4.24
Swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		14,000			14,000				14,000
Weighted average fixed price | $ / MMBTU		4.19			4.19				4.19
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		12,700			12,700				12,700
Weighted average fixed price | $ / MMBTU		3.64			3.64				3.64
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		8,250			8,250				8,250
Weighted average fixed price | $ / MMBTU		3.83			3.83				3.83
Swaps with Deferred Premium | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume | bbl		630,000	[1]		630,000	[1]			630,000	[1]			1,100,000
Weighted average fixed price	[1]	91.38			91.38				91.38
Weighted average fixed price per Bbl, Average premium | $ / contract	[1]	13.80			13.80				13.80
Deferred premium for swaps on commodity derivative contracts | $													$ 12,424
Effective fixed price net of premiums													82.34
Three-way collars
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $					$ (42)			77	$ (42)		1,338
Three-way collars | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl		240,000			240,000				240,000
Weighted average fixed price per Bbl, sold puts		84			84				84
Weighted average fixed price per Bbl, purchased puts		92			92				92
Weighted average fixed price per Bbl, sold calls		101.01			101.01				101.01
Enhanced Swaps | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[2]	3,720,000			3,720,000				3,720,000
Weighted average fixed price	[2]	92.94			92.94				92.94
Weighted average fixed price per Bbl, sold puts	[2]	80.52			80.52				80.52
Floor price (usd per barrel)		60			60				60
Purchased Puts | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]	695,000			695,000				695,000
Weighted average fixed price per Bbl, purchased puts	[1]	43.05			43.05				43.05
Weighted average fixed price per Bbl, Average premium | $ / contract	[1]	2.96			2.96				2.96
Purchased Puts | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[2]	3,720,000			3,720,000				3,720,000
Weighted average fixed price per Bbl, purchased puts	[2]	60			60				60
Premium paid for put options on commodity derivative contracts | $				$ 20,609
Natural gas basis protection swaps
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $					$ 64			$ 285	$ (56)		$ 390
Natural gas basis protection swaps | Derivative Maturing in 2015 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		3,600			3,600				3,600
Weighted average fixed price | $ / MMBTU		0.24			0.24				0.24
Natural gas basis protection swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		8,400			8,400				8,400
Weighted average fixed price | $ / MMBTU		0.36			0.36				0.36
Early settlement | Oil Derivative
Derivative [Line Items]
Volume | bbl														495,000
Early settlement | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU														12,280
Settlement of non-hedge derivative instruments, net proceeds | $							$ 15,395
Collar with deferred premium | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]	130,000			130,000				130,000
Weighted average fixed price per Bbl, purchased puts	[1]	47.50			47.50				47.50
Weighted average fixed price per Bbl, sold calls	[1]	57.50			57.50				57.50
Weighted average fixed price per Bbl, Average premium | $ / contract	[1]	1.71			1.71				1.71
Collar with deferred premium | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]	480,000			480,000				480,000
Weighted average fixed price per Bbl, sold puts	[1]	40			40				40
Weighted average fixed price per Bbl, purchased puts	[1]	52.50			52.50				52.50
Weighted average fixed price per Bbl, sold calls	[1]	72.50			72.50				72.50
Weighted average fixed price per Bbl, Average premium | $ / contract	[1]	2.95			2.95				2.95
Collar with deferred premium | Derivative Maturing in 2017 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]	480,000			480,000				480,000
Weighted average fixed price per Bbl, sold puts	[1]	42.50			42.50				42.50
Weighted average fixed price per Bbl, purchased puts	[1]	55			55				55
Weighted average fixed price per Bbl, sold calls	[1]	80			80				80
Weighted average fixed price per Bbl, Average premium | $ / contract	[1]	2.78			2.78				2.78
Locked-In swaps with deferred premium | Derivative Maturing in 2015 | Oil Derivative
Derivative [Line Items]
Volume | bbl		825,000			825,000				825,000			1,100,000
Effective fixed price net of premiums		82.72			82.72				82.72			82.68
Locked-In swaps with deferred premium | Derivative Maturing in September 2015 | Oil Derivative
Derivative [Line Items]
Derivative nonmonetary notional amount, matured | bbl		275,000			275,000				275,000
Net proceeds from matured derivative instrument | $		$ 10,196
[1]	These contracts include deferred premiums that are payable upon settlement.
[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 $48.70 for 2016 as of September 30, 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 ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Fair value of derivative instruments
Derivative assets, gross		$ 187,564	$ 251,863
Netting adjustments	[1]	3,854	232
Current derivative assets, net		142,944	179,921
Long-term derivative assets, net		40,766	71,710
Derivative liabilities, gross		(3,893)	(309)
Derivative Liability, Netting adjustments	[1]	(3,854)	(232)
Current derivative liabilities, net		(39)	(77)
Long-term derivative liabilities, net		0	0
Derivative assets (liabilities), net		183,671	251,554
Current derivative assets (liabilities), net		142,905	179,844
Long-term derivative assets (liabilities), net		40,766	71,710
Natural Gas Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross		39,554	32,939
Derivative liabilities, gross		0	0
Derivative assets (liabilities), net		39,554	32,939
Natural Gas Derivative | Natural gas basis protection swaps
Fair value of derivative instruments
Derivative assets, gross		0	292
Derivative liabilities, gross		(1,159)	(309)
Derivative assets (liabilities), net		(1,159)	(17)
Oil Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross		9,386	23,465
Derivative liabilities, gross		(1,810)	0
Derivative assets (liabilities), net		7,576	23,465
Oil Derivative | Three-way collars
Fair value of derivative instruments
Derivative assets, gross		3,483	1,175
Derivative liabilities, gross		0	0
Derivative assets (liabilities), net		3,483	1,175
Oil Derivative | Enhanced swaps
Fair value of derivative instruments
Derivative assets, gross		60,755	100,724
Derivative liabilities, gross		0	0
Derivative assets (liabilities), net		60,755	100,724
Oil Derivative | Purchased and sold puts
Fair value of derivative instruments
Derivative assets, gross		74,386	93,268
Derivative liabilities, gross		(924)	0
Derivative assets (liabilities), net		$ 73,462	$ 93,268
[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 instruments (Derivat

Derivative instruments (Derivative Settlements Outstanding) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative settlements receivable included in accounts receivable	$ 37,388	$ 19,678

Derivative instruments (Effec37

Derivative instruments (Effect of Derivative Instruments on the Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Non-Hedge Derivative Gains (Losses) [Line Items]
Non-hedge derivative losses	$ 85,415	$ 104,413	$ 105,266	$ 17,218
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	6,583	20,039	(9,274)	16,794
(Payments on) receipts from settlement of non-hedge derivative instruments	12,829	(1,030)	43,806	(12,653)
Three-way collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	1,803	6,870	2,307	106
(Payments on) receipts from settlement of non-hedge derivative instruments	42	(77)	42	(1,338)
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	23,590	80,551	(59,775)	27,521
(Payments on) receipts from settlement of non-hedge derivative instruments	41,667	(1,664)	129,245	(10,657)
Natural gas basis protection swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(1,035)	9	(1,141)	(2,165)
(Payments on) receipts from settlement of non-hedge derivative instruments	$ (64)	$ (285)	$ 56	$ (390)

Fair value measurements (Recurr

Fair value measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross		$ 187,564	$ 251,863
Derivative liabilities, gross		(3,893)	(309)
Derivative assets (liabilities), net		183,671	251,554
Derivative assets, amount offset		(3,854)	(232)
Derivative liabilities, amounts offset		3,854	232
Derivative assets, net		183,710	251,631
Derivative liabilities, net		(39)	(77)
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net		183,671	251,554
Derivative assets, amount offset	[1]	(3,854)	(232)
Derivative liabilities, amounts offset	[1]	3,854	232
Derivative assets, net		183,710	251,631
Derivative liabilities, net		(39)	(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		48,940	56,696
Derivative liabilities, gross		(2,969)	(309)
Derivative assets (liabilities), net		45,971	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		138,624	195,167
Derivative liabilities, gross		(924)	0
Derivative assets (liabilities), net		$ 137,700	$ 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 ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Level 3 Rollforward
Beginning balance	$ 195,167	$ 3,622
Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)	4,660	15,632
Purchases	0	1,220
Settlements (received) paid	(62,127)	11,995
Ending balance	137,700	32,469
Losses relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$ 45,835	$ 24,156

Fair value measurements (Nonrec

Fair value measurements (Nonrecurring Fair Value Measurements) (Details) - Significant unobservable inputs (Level 3) - Nonrecurring fair value measurements	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Nonrecurring Fair Value Measurements
Annual inflation rate	2.91%	2.95%
Credit-adjusted risk-free interest rate	13.45%	6.60%

Fair value measurements (Fair V

Fair value measurements (Fair Value of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	$ 394,000	$ 347,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	295,618	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	554,272	554,869
Significant other observable inputs (Level 2) | Carrying value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	394,000	347,000
Other secured long-term debt	12,604	14,957
Long-term debt	1,656,494	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	$ 295,618	295,139
Stated interest rate	9.875%
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
Stated interest rate	8.25%
Significant other observable inputs (Level 2) | Carrying value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	$ 554,272	554,869
Stated interest rate	7.625%
Significant other observable inputs (Level 2) | Estimated fair value
Fair Value of Other Financial Instruments
Senior secured revolving credit facility	$ 394,000	347,000
Other secured long-term debt	12,604	14,957
Long-term debt	780,104	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	97,500	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	122,000	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	$ 154,000	$ 379,775

Fair value measurements (Counte

Fair value measurements (Counterparty Credit Risk) (Details) $ in Thousands	Sep. 30, 2015USD ($)financial_institutions
Counterparty Credit Risk
Derivative liabilities subject to acceleration | $	$ (3,893)
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 ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative assets, gross		$ 187,564	$ 251,863
Derivative assets, amount offset		(3,854)	(232)
Derivative assets		183,710	251,631
Derivative assets, not offset	[1]		0
Credit facility balance available to offset net derivative assets		(114,282)	(118,430)
Derivative asset, net		69,428	133,201
Derivative liabilities, gross		(3,893)	(309)
Derivative liabilities, amounts offset		3,854	232
Derivative liabilities		39	77
Derivative liabilities, not offset	[1]		0
Derivative liability, net		(39)	(77)
Derivative Asset (Liability), Fair Value, Gross Asset		183,671	251,554
Derivative Asset (Liability), Fair Value, Gross Liability		0	0
Derivative Asset (Liability), Net		183,671	251,554
Credit facility balance available to offset net derivative assets		(114,282)	(118,430)
Derivative asset (liability), net		$ 69,389	$ 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 ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 47,424	$ 55,179
Liabilities incurred in current period	1,852	4,844
Liabilities settled and disposed in current period	(4,886)	(16,807)
Revisions in estimated cash flows	1,785	2,274
Accretion expense	2,727	2,991
Ending balance	48,902	48,481
Less current portion included in accounts payable and accrued liabilities	2,384	4,997
Asset retirement obligations	$ 46,518	$ 43,484	$ 43,277

Stock-based compensation (Phant

Stock-based compensation (Phantom Stock Plan and Restricted Stock Unit Plan) (Details) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)$ / sharesshares
Vest date fair value
Aggregate intrinsic value of unvested phantom shares and RSUs outstanding | $	$ 5,269
Phantom Stock Plan | Phantom Shares
Stock-Based Compensation [Line Items]
Award vesting period (in years)	5 years
Days from vesting date to cash settlement	120 days
Weighted average grant date fair value
Unvested and outstanding at beginning of period ($ per share)	$ 20.18
Granted ($ per share)	0
Vested ($ per share)	24.48
Forfeited ($ per share)	18.34
Unvested and outstanding at end of period ($ per share)	$ 18.61
Shares
Unvested and outstanding at beginning of period (in shares) | shares	23,179
Granted (in shares) | shares	0
Vested (in shares) | shares	(6,456)
Forfeited (in shares) | shares	(6,032)
Unvested and outstanding at end of period (in shares) | shares	10,691
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
Unvested and outstanding at beginning of period ($ per share)	$ 9.91
Granted ($ per share)	14.88
Vested ($ per share)	10.73
Forfeited ($ per share)	9.62
Unvested and outstanding at end of period ($ per share)	$ 10.48
Shares
Unvested and outstanding at beginning of period (in shares) | shares	569,160
Granted (in shares) | shares	59,571
Vested (in shares) | shares	(216,941)
Forfeited (in shares) | shares	(133,132)
Unvested and outstanding at end of period (in shares) | shares	278,658
Vest date fair value
Vest date fair value | $	$ 857
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU) | Maximum
Stock-Based Compensation [Line Items]
Award vesting period (in years)	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 ($ per share)	$ 0
Weighted average remaining contractual term	1 year 3 months 27 days

Stock-based compensation (Cash

Stock-based compensation (Cash Incentive Plan) (Details) - The 2015 Cash LTIP $ in Thousands	3 Months Ended
	Sep. 30, 2015USD ($)
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred Compensation Arrangement with Individual, Requisite Service Period	4 years
Cash award granted	$ 3,297

Stock-based compensation (2010

Stock-based compensation (2010 Equity Incentive Plan) (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Vest date fair value
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding	$ 5,269
Restricted Stock | 2010 Equity Incentive Plan | Maximum | Service Vesting Conditions
Stock-Based Compensation [Line Items]
Award vesting period (in years)	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
Unvested and outstanding at beginning of period ($ per share)	$ 791.52
Granted ($ per share)	533.80
Vested ($ per share)	778.81
Forfeited ($ per share)	774.21
Unvested and outstanding at end of period ($ per share)	$ 792.78
Shares
Unvested and outstanding at beginning of period (in shares)	25,834
Granted (in shares)	610
Vested (in shares)	(8,325)
Forfeited (in shares)	(3,997)
Unvested and outstanding at end of period (in shares)	14,122
Vest date fair value
Vest date fair value	$ 4,444
Restricted stock used for tax withholding	5,678	1,810
Shares expected to be repurchased during the next twelve months	2,000
Estimated fair value per share at end of period ($ per share)	$ 373.10
Restricted Stock | 2010 Equity Incentive Plan | Common Class A | Performance Vested
Weighted average grant date fair value
Unvested and outstanding at beginning of period ($ per share)	292.92
Granted ($ per share)	113.90
Vested ($ per share)	0
Forfeited ($ per share)	323.53
Unvested and outstanding at end of period ($ per share)	$ 278.97
Shares
Unvested and outstanding at beginning of period (in shares)	38,943
Granted (in shares)	599
Vested (in shares)	0
Forfeited (in shares)	(11,094)
Unvested and outstanding at end of period (in shares)	28,448

Stock-based compensation (Stock

Stock-based compensation (Stock-based compensation cost) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ (581)	$ 2,309	$ (143)	$ 9,026
Less: stock-based compensation cost capitalized	(49)	(289)	(352)	(2,735)
Stock-based compensation expense	(630)	2,020	(495)	6,291
Payments for stock-based compensation	333	$ 699	3,977	$ 2,787
Stock-based compensation costs included in accrued payroll and benefits payable	1,384		1,384		$ 4,830
Unrecognized compensation cost	$ 7,134		$ 7,134
Years over which unrecognized compensation cost is expected to be recognized			1 year 9 months

Commitments and contingencies (

Commitments and contingencies (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Jun. 07, 2011	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Loss Contingencies [Line Items]
Letters of credit outstanding		$ 874		$ 920
Interest paid		77,437	$ 74,446
Pending Litigation | Minimum
Loss Contingencies [Line Items]
Damages sought	$ 5,000
Letter of Credit
Loss Contingencies [Line Items]
Proceeds from Letters		0	0
Interest paid		$ 0	$ 0