Chaparral Energy (CHAP) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 25, 2016	Jun. 30, 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-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Public Float			$ 0
Common Class A
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		334,545
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		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 17,065	$ 31,492
Accounts receivable, net		79,000	98,444
Inventories, net		12,329	25,557
Prepaid expenses		3,700	4,484
Derivative instruments		143,737	179,921
Total current assets		255,831	339,898
Property and equipment—at cost, net		48,962	66,561
Oil and natural gas properties, using the full cost method:
Proved		4,128,193	3,735,817
Unevaluated (excluded from the amortization base)		66,905	288,425
Accumulated depreciation, depletion, amortization and impairment		(3,396,261)	(1,701,851)
Total oil and natural gas properties		798,837	2,322,391
Derivative instruments		19,501	71,710
Deferred income taxes		53,914	0
Other assets		27,694	31,256
Total assets		1,204,739	2,831,816
Current liabilities:
Accounts payable and accrued liabilities		66,222	191,957
Accrued payroll and benefits payable		15,305	21,654
Accrued interest payable		23,303	24,106
Revenue distribution payable		12,391	24,467
Long-term debt and capital leases, classified as current	[1]	1,607,127	5,377
Derivative instruments		0	77
Deferred income taxes		53,914	60,728
Total current liabilities		1,778,262	328,366
Long-term debt and capital leases, less current maturities			1,628,425
Stock-based compensation		400	3,131
Asset retirement obligations		46,434	43,277
Deferred income taxes		$ 0	$ 116,759
Commitments and contingencies (Note 14)
Stockholders’ (deficit) equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		$ 0	$ 0
Additional paid in capital		431,307	429,678
(Accumulated deficit) retained earnings		(1,051,678)	282,166
Total stockholders' (deficit) equity		(620,357)	711,858
Total liabilities and stockholders' (deficit) equity		1,204,739	2,831,816
Common Class A
Stockholders’ (deficit) equity:
Common stock		4	4
Common Class B
Stockholders’ (deficit) equity:
Common stock		3	3
Common Class C
Stockholders’ (deficit) equity:
Common stock		2	2
Common Class E
Stockholders’ (deficit) equity:
Common stock		5	5
Common Class F
Stockholders’ (deficit) equity:
Common stock		0	0
Common Class G
Stockholders’ (deficit) equity:
Common stock		$ 0	$ 0
[1]	As a result of defaults on our debt as of the filing date of this report, our long-term debt was classified as current at December 31, 2015.

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Preferred stock, shares authorized	600,000	600,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, shares outstanding	1,404,309	1,423,916
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	345,289	364,896
Common stock, shares outstanding	345,289	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	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Commodity sales	$ 324,315	$ 681,557	$ 591,674
Gain from oil hedging activities	0	0	37,134
Total revenues	324,315	681,557	628,808
Costs and expenses:
Lease operating	110,659	141,608	132,690
Transportation and processing	8,541	8,295	7,081
Production taxes	9,953	28,305	33,266
Depreciation, depletion and amortization	216,574	245,908	192,426
Loss on impairment of oil and gas assets	1,491,129	0	0
Loss on impairment of other assets	16,207	0	3,490
General and administrative	39,089	53,414	53,883
Cost reduction initiatives	10,028	0	0
Total costs and expenses	1,902,180	477,530	422,836
Operating (loss) income	(1,577,865)	204,027	205,972
Non-operating income (expense):
Interest expense	(112,400)	(104,241)	(96,876)
Gain on extinguishment of debt	31,590	0	0
Non-hedge derivative gains (losses)	145,288	231,320	(21,635)
Other income, net	2,324	2,630	1,075
Net non-operating income (expense)	66,802	129,709	(117,436)
(Loss) income before income taxes	(1,511,063)	333,736	88,536
Income tax (benefit) expense	(177,219)	124,443	32,849
Net (loss) income	$ (1,333,844)	$ 209,293	$ 55,687

Consolidated statements of comp

Consolidated statements of comprehensive income (loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Comprehensive (loss) income
Net (loss) income	$ (1,333,844)	$ 209,293	$ 55,687
Other comprehensive (loss) income
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations	0	0	(37,134)
Income tax benefit related to other comprehensive loss	0	0	13,911
Other comprehensive loss, net of tax	0	0	(23,223)
Comprehensive (loss) income	$ (1,333,844)	$ 209,293	$ 32,464

Consolidated statements of stoc

Consolidated statements of stockholders' equity (deficit) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid in Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)
Stockholders' equity, balance at beginning of the period at Dec. 31, 2012	$ 462,857	$ 14	$ 422,434	$ 17,186	$ 23,223
Balance at beginning of period (in shares) at Dec. 31, 2012	1,420,034	1,420,034
Restricted stock issuances	8,056	8,056
Restricted stock forfeited	(4,905)	(4,905)
Restricted stock repurchased		(1,025)
Stock-based compensation	$ 1,943	$ 0	1,943	0	0
Net income (loss)	55,687	0	0	55,687	0
Other comprehensive loss, net of tax	(23,223)	0	0	0	(23,223)
Stockholders' equity, balance at end of the period at Dec. 31, 2013	$ 497,264	$ 14	424,377	72,873	0
Balance at end of period (in shares) at Dec. 31, 2013	1,422,160	1,422,160
Restricted stock issuances	15,278	15,278
Restricted stock forfeited	(11,497)	(11,497)
Restricted stock repurchased		(2,025)
Stock-based compensation	$ 5,301	$ 0	5,301	0	0
Net income (loss)	209,293	0	0	209,293	0
Other comprehensive loss, net of tax	0
Stockholders' equity, balance at end of the period at Dec. 31, 2014	$ 711,858	$ 14	429,678	282,166	0
Balance at end of period (in shares) at Dec. 31, 2014	1,423,916	1,423,916
Restricted stock issuances	1,209	1,209
Restricted stock forfeited	(15,091)	(15,091)
Restricted stock repurchased		(5,725)
Stock-based compensation	$ 1,629	$ 0	1,629	0	0
Net income (loss)	(1,333,844)	0	0	(1,333,844)	0
Other comprehensive loss, net of tax	0
Stockholders' equity, balance at end of the period at Dec. 31, 2015	$ (620,357)	$ 14	$ 431,307	$ (1,051,678)	$ 0
Balance at end of period (in shares) at Dec. 31, 2015	1,404,309	1,404,309

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net (loss) income	$ (1,333,844)	$ 209,293	$ 55,687
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	216,574	245,908	192,426
Loss on impairment of assets	1,507,336	0	3,490
Deferred income taxes	(177,487)	123,891	31,734
Gain on hedge reclassification adjustments	0	0	(37,134)
Non-hedge derivative (gains) losses	(145,288)	(231,320)	21,635
Gain on sale of assets	(1,584)	(2,152)	(670)
Gain on extinguishment of debt	(31,590)	0	0
Other	6,057	4,294	4,418
Change in assets and liabilities
Accounts receivable	15,720	4,692	(21,216)
Inventories	(1,968)	(5,516)	(5,923)
Prepaid expenses and other assets	481	(750)	(1,299)
Accounts payable and accrued liabilities	(17,200)	(24,652)	9,977
Revenue distribution payable	(12,075)	(671)	6,986
Stock-based compensation	(5,524)	894	3,942
Net cash provided by operating activities	19,608	323,911	264,053
Cash flows from investing activities
Expenditures for property, plant, and equipment	(313,481)	(685,459)	(491,022)
Acquisition of a business	0	0	(153,858)
Proceeds from asset dispositions	42,618	291,429	111,246
Settlement of non-hedge derivative instruments	233,605	2,417	19,113
Derivative premiums paid and other	0	(20,609)	(601)
Net cash used in investing activities	(37,258)	(412,222)	(515,122)
Cash flows from financing activities
Proceeds from long-term debt	120,000	302,115	297,797
Repayment of long-term debt	(102,978)	(228,594)	(52,100)
Repurchase of Senior Notes	(9,995)	0	0
Proceeds from sale and leaseback of assets	0	0	24,500
Principal payments under capital lease obligations	(2,400)	(2,313)	(352)
Payment of other financing fees	(1,404)	0	0
Net cash provided by financing activities	3,223	71,208	269,845
Net (decrease) increase in cash and cash equivalents	(14,427)	(17,103)	18,776
Cash and cash equivalents at beginning of period	31,492	48,595	29,819
Cash and cash equivalents at end of period	$ 17,065	$ 31,492	$ 48,595

Nature of operations and summar

Nature of operations and summary of significant accounting policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Nature of operations and summary of significant accounting policies	Note 1: Nature of operations and summary of significant accounting policies Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and Texas. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. Principles of consolidation The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates. Reclassifications Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations. Cash and cash equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2015, cash with a recorded balance totaling $13,507 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. We are not party to any valid blocked account agreements with respect to any material amount of cash. 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 December 31: 2015 2014 Joint interests $ 14,149 $ 30,648 Accrued commodity sales 21,645 45,667 Derivative settlements 40,380 19,678 Other 3,329 2,738 Allowance for doubtful accounts (503 ) (287 ) $ 79,000 $ 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 $10,192 on our equipment inventory for the year ended December 31, 2015. The adjustment was recorded to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity decreased in the 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 consisted of the following at December 31: 2015 2014 Equipment inventory $ 11,470 $ 24,169 Commodities 1,698 2,575 Inventory valuation allowance (839 ) (1,187 ) $ 12,329 $ 25,557 Property and equipment Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently. Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows: Furniture and fixtures 10 years Automobiles and trucks 5 years Machinery and equipment 10 — 20 years Office and computer equipment 5 — 10 years Building and improvements 10 — 40 years Oil and natural gas properties Capitalized Costs . We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the acquisition, 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, lease bonus payments, 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. As of December 31, 2015, unevaluated oil and natural gas properties include $60,031 of capital costs incurred for undeveloped acreage and $6,874 for wells and facilities in progress pending determination. As of December 31, 2014, work in progress costs included $190,356 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO 2 2 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 December 31, 2015, 2014, and 2013 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). Due to the substantial decline of commodity prices that began in late 2014 and continued through 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 year ended December 31, 2015 of $1,491,129. Further write-downs may occur if prices remain at current levels or continue to decline subsequent to December 31, 2015. 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 $6,015, nil and $3,490 related to certain of our drilling rigs during the years ended December 31, 2015, 2014 and 2013, respectively. The drilling rigs were previously classified as held for sale but were reclassified to property and equipment in late 2013 when the ultimate disposal became uncertain. 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 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. Income taxes Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized. See “Note 10—Income taxes” for further discussion of our valuation allowance. If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2015 and 2014, we have no uncertain tax positions and as such have not recorded a liability or accrued interest or penalties related to uncertain tax positions. We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2008 through 2015 tax years generally remain subject to examination by federal and state tax authorities. Derivative transactions We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in “Non-hedge derivative gains (losses)” in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities. Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and was reclassified into income as the hedged transactions occurred. As of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 7 —Derivative instruments” for additional information regarding our derivative transactions. Fair value measurements Fair value is defined by the Financial Accounting Standards Board (“FASB”) as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, our drilling rigs which we have impaired and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 8 —Fair value measurements” for additional information regarding our fair value measurements. Valuation of business combinations In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting. Asset retirement obligations We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in “Depreciation, depletion and amortization” in our consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 9 —Asset retirement obligations” for additional information regarding our asset retirement obligations. Environmental liabilities We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows. Revenue recognition Sales of oil, natural gas and NGLs are recorded when title of production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products are recognized at the time of delivery of materials. Gas balancing In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2015 and, 2014 our aggregate imbalance due to under production was approximately 0 MMcf and 2,005 MMcf, respectively. As of December 31, 2015 and 2014, our aggregate imbalance due to over production was approximately 1,253 MMcf and 1,276 MMcf, respectively, and a liability for gas imbalances of $1,303 and $1,110, respectively, was included in accounts payable and accrued liabilities. Stock-based compensation Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan. The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting. We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted. The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. See “Note 11 —Stock-based compensation” for additional information relating to stock-based compensation. 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 $10,028 of expenses for cost reduction initiatives for the year ended December 31, 2015, is $7,757 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 accounting pronouncements Other Expenses . In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations. Recently issued accounting pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. 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 permitted only for fiscal years beginning after December 31, 2016, and interim periods thereafter. 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 were not affected by the amendment. This guidance, which was effective and adopted by us in the first quarter of 2016, only affects the presentation of our consolidated balance sheets and does not have a material impact on our consolidated financial statements. 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 beginning 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 November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying component of a jurisdiction) to be presented as a net current asset or liability and net noncurrent asset or liability. This requires a jurisdiction-by-jurisdiction analysis based on the classification of the assets and liabilities to which the underlying temporary differences relate, or, in the case of loss or credit carryforwards, based on the period in which the attribute is expected to be realized. Any valuation allowance is then required to be allocated on a pro rata basis, by jurisdiction, between current and noncurrent deferred tax assets. To simplify presentation, the new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. Importantly, the guidance does not change the existing requirement that only permits offsetting within a jurisdiction – that is, companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. The guidance is effective for public business entities in fiscal periods beginning after December 15, 2016, and interim periods thereafter. We do not expect this guidance to have a significant impact on our consolidated financial statements, other than balance sheet reclassifications. In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations. In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.

Going Concern and Liquidity

Going Concern and Liquidity	12 Months Ended
	Dec. 31, 2015
Going Concern And Liquidity [Abstract]
Going Concern and Liquidity	Note 2: Going concern and liquidity Oil and natural gas prices have declined severely since mid 2014 and continue to be depressed in 2016. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity position. As of December 31, 2015, the total outstanding principal amount of our debt obligations was $1,607,127. For additional detail on each of our debt obligations, see “Note 6—Debt” Our borrowing base under our Credit Facility is subject to its next semi-annual redetermination on May 1, 2016. As a result of depressed market prices in early 2016, we anticipate that the lender-determined pricing that will be utilized to estimate our borrowing base under our Credit Facility will be lower than the pricing utilized in our previous redetermination. Thus, we believe that our borrowing base may be decreased significantly. Since our Credit Facility is fully drawn, any decrease in our borrowing base as a result of the redetermination will result in a deficiency and we would have to repay any outstanding indebtedness in excess of the reduced borrowing base at our election within 30 days or in six monthly installments thereafter. Based on current market conditions and depressed commodity prices, if we are unable to restructure our debt and adequately address liquidity concerns, we do not expect to be in compliance with the Consolidated Net Secured Debt to EBITDAX (as defined in “Note 6 – Debt”) and Interest Coverage Ratio covenants for the quarter ending September 30, 2016. A failure to meet our financial covenants is an event of default under our Credit Facility which may result in the total outstanding amount on the facility being immediately due. The consolidated financial statements included in this Annual Report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. We incurred a net loss of approximately $1,333,844 during the year ended December 31, 2015, and as of that date, our current liabilities exceeded current assets by approximately $1,522,431 and our equity was a deficit of $620,357. Due to the uncertainty associated with our ability to repay our outstanding debt obligations as they become due, especially in the event of any acceleration of indebtedness, there is substantial doubt about our ability to continue as a going concern. We have reclassified all our long-term debt to current liabilities as of December 31, 2015, due to the defaults and cross defaults on these facilities discussed below, which could result in an acceleration of outstanding amounts. Other than this reclassification, the consolidated financial statements do not reflect any adjustments that might result from the outcome of the uncertainties as discussed herein. We have substantial Our Credit Facility requires that our annual If we are unable to reach an agreement with our creditors prior to any of the above described accelerations, we could be required to file for protection under Chapter 11 of the U.S. Bankruptcy Code. We are currently pursuing and evaluating several alternatives including (i) debt- for-debt exchanges or debt-for-equity exchanges, (ii) potentially seeking relief under Chapter 11 of the U.S. Bankruptcy Code, (iii) obtaining waivers or amendments from our lenders, (iv) minimizing our planned capital investments, (v) effectively managing our working capital, (vi) improving our cash flows from operations and (vii) dispositions of non-core assets. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain obligations. As discussed in “Note 8 – Fair value measurements” all the counterparties to our derivative transactions are also financial institutions within the lender group under our Credit Facility. Our derivative contracts with these counterparties are governed by master agreements which generally specify that a default under any of our indebtedness as well as any bankruptcy filing is an event of default which may result in early termination of the derivative contracts. In the event of an early termination of our derivative contracts as a result of a default, we may not receive the proceeds from such termination. It is possible that the counterparty financial institutions to our derivative contracts will utilize their right of offset with respect to the Credit Facility to retain such proceeds. Any potential loss of anticipated proceeds from our derivative settlements in 2016 will severely limit our cash from operations and liquidity. Furthermore, if we are in default on our indebtedness or have a bankruptcy filing, we will no longer be able to represent that we comply with the credit default or bankruptcy covenants under our derivative master agreements and thus may not be able to enter into new hedging transactions. On March 4, 2016, we received notification from one of our derivative counterparties reserving all rights under the master agreement governing our derivative transaction with said counterparty. The notice was issued subsequent to our election to defer the Senior Note interest payment on March 1, 2016, which according to the counterparty represents an event of default.

Supplemental disclosures to the

Supplemental disclosures to the consolidated statements of cash flows	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental disclosures to the consolidated statements of cash flows	Note 3: Supplemental disclosures to the consolidated statements of cash flows Supplemental disclosures to the consolidated statements of cash flows are presented below: Year ended December 31, 2015 2014 2013 Net cash provided by operating activities included: Cash payments for interest $ 116,379 $ 112,196 $ 107,122 Interest capitalized (9,670 ) (13,491 ) (15,995 ) Cash payments for interest, net of amounts capitalized $ 106,709 $ 98,705 $ 91,127 Cash payments for income taxes $ 640 591 641 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 4,000 $ 7,461 $ 9,036 Change in accrued oil and gas capital expenditures $ (105,312 ) $ 43,971 $ 27,875

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and divestitures	Note 4: Acquisitions and divestitures 2015 Divestitures During 2015, we sold various non-core oil and gas properties for total proceeds of $36,654. 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. 2014 Divestitures During 2014, we closed on the sales of four of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23,702 and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124,717. In July 2014, we sold our Ark-La-Tex and Central Basin Platform property packages to RAM Energy, LLC (“RAM”) for cash proceeds of $49,078 and $46,830, respectively. Proceeds from these property packages are net of post-closing adjustments. 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. In addition to the packages discussed above, we had various other divestitures during the year ended December 31, 2014. These divestitures resulted in cash proceeds of $20,007 from the sale of leasehold interests in the Eagle Ford Formation in Texas and $24,478 from the sale of various other properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma. 2013 Acquisition and divestitures Cabot Acquisition . In late 2013, we acquired additional oil and natural gas properties consisting of approximately 131,000 (66,000 net) acres in the Panhandle Marmaton play from Cabot Oil & Gas Corporation for approximately $153,858, net of pre-closing purchase price adjustments and subject to post closing adjustments (the “Cabot Acquisition”). The Cabot Acquisition expanded our presence in the Panhandle Marmaton play, adding oil and natural gas reserves and production to our existing asset base in this area. Our acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the December 18, 2013 acquisition date, which was the date on which we obtained control of the properties. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See “Note 8—Fair value measurements” for additional discussion of the measurement inputs. We estimated the consideration paid for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. Acquisition-related costs of $951 have been expensed as incurred in general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013. The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013. Consideration paid Cash, net of purchase price adjustments $ 153,858 Fair value of identifiable assets acquired and liabilities assumed Oil and natural gas properties Proved $ 67,275 Unevaluated 87,663 Asset retirement obligations (1,080 ) Fair value of net identifiable assets acquired $ 153,858 The following unaudited pro forma combined results of operations for the year ended December 31, 2013 is presented as though we completed the Cabot Acquisition as of January 1, 2012. The pro forma combined results of operations for the year ended December 31, 2013 has been prepared by adjusting the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by us in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects. Year ended December 31, 2013 Revenues $ 690,564 Operating expenses $ 448,751 Net income $ 76,552 Divestitures. During 2013, we sold various oil and natural gas properties for total cash proceeds of approximately $109,710. These included properties in Creek, Love and Carter counties, Oklahoma, that were sold for approximately $61,440 and properties in Texas County, Oklahoma, that were sold for approximately $17,800. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Property and equipment	Note 5: Property and equipment Major classes of property and equipment consist of the following at December 31: 2015 2014 Furniture and fixtures $ 2,518 $ 2,488 Automobiles and trucks 10,689 13,721 Machinery and equipment 55,963 57,922 Office and computer equipment 19,993 18,305 Building and improvements 25,534 29,322 114,697 121,758 Less accumulated depreciation and amortization 75,041 64,310 39,656 57,448 Land 9,306 9,113 $ 48,962 $ 66,561

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Note 6: Debt As of the dates indicated, debt consists of the following: December 31, 2015 2014 9.875% Senior Notes due 2020, net of discount of $4,185 and $4,861, respectively $ 293,815 $ 295,139 8.25% Senior Notes due 2021 384,045 400,000 7.625% Senior Notes due 2022, including premium of $4,939 and $4,869, respectively 530,849 554,869 Credit Facility 367,000 347,000 Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.16% to 5.46%, due August 2021 through December 2028; collateralized by real property 10,182 10,705 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95%, due January 2016 through February 2018; collateralized by automobiles, machinery and equipment 1,799 4,252 Capital lease obligations 19,437 21,837 Total debt, net 1,607,127 1,633,802 Less current portion (1) 1,607,127 5,377 Total long-term debt, net $ — $ 1,628,425 (1) As a result of defaults on our debt as of the filing date of this report, our long-term debt was classified as current at December 31, 2015. Absent any acceleration of our debt resulting from defaults, the maturities of debt and capital leases, and excluding premiums or discounts on our Senior Notes, would be as follows as of December 31, 2015: 2016 $ 4,409 2017 370,600 2018 3,302 2019 12,328 2020 298,687 2021 and thereafter 917,047 $ 1,606,373 Senior Notes The Senior Notes, which, as of December 31, 2015, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The Senior Notes are redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption. Interest on the Senior Notes is payable semi-annually, and the principal is due upon maturity. Certain of the Senior Notes were issued at a discount or a premium which is amortized to interest expense over the term of the respective series of Senior Notes. Net amortization of the discount (premium) was $945, $(268), and $(387) during the years ended December 31, 2015, 2014 and 2013, respectively. We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things: · incur or guarantee additional debt and issue certain types of preferred stock; · pay dividends on capital stock or redeem, repurchase, or retire capital stock or subordinated debt; · make investments; · incur liens on assets; · create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us; · engage in transactions with affiliates; · sell assets, including capital stock of our subsidiaries; · consolidate, merge or transfer assets; and · enter into other lines of business. If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest. Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Chaparral Biofuels, LLC. As discussed in “Note 2—Going concern and liquidity,” we deferred an interest payment due on our Senior Notes on March 1, 2016, and do not intend to make the payment prior to the expiration of the 30-day grace period. As such, we will be in default under the indenture governing our Senior Notes as of March 31, 2016. Credit Facility In April 2010, we entered into an Eighth Restated Credit Agreement, which is collateralized by our oil and natural gas properties and, as amended, is originally scheduled to mature on November 1, 2017. Availability under our Credit Facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on our Credit Facility for 2015 was $650,000. Our first semiannual borrowing base redetermination for the current year was finalized in conjunction with an amendment to our Credit Facility (the “Fifteenth Amendment”), effective on April 1, 2015, and reduced the borrowing base to $550,000. Our next semiannual borrowing base redetermination, which was effective on October 29, 2015, reaffirmed our borrowing base at $550,000. Amounts borrowed under our Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2015 was subject to the Eurodollar rate. In the event of a default under the Credit Facility, subsequent interest on outstanding amounts will be charged by our lenders based on the ABR plus an additional 2.00% and plus the applicable margin. The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our Credit Facility, plus a margin that varies depending on our utilization percentage. During 2015, the applicable margin varied from 2.00% to 2.25%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than 3 months or every 3 months. Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our Credit Facility, (2) the Federal Funds Effective Rate, as defined in our Credit Facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our Credit Facility, plus 1.00%, plus a margin that varies depending on our utilization percentage. We did not have loans subject to the ABR during 2015. Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium. Our Credit Facility contains restrictive covenants that may limit our ability, among other things, to: · incur additional indebtedness; · create or incur additional liens on our oil and natural gas properties; · pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness; · make investments in or loans to others; · change our line of business; · enter into operating leases; · merge or consolidate with another person, or lease or sell all or substantially all of our assets; · sell, farm-out or otherwise transfer property containing proved reserves; · enter into transactions with affiliates; · issue preferred stock; · enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends; · enter into or terminate certain swap agreements; · amend our organizational documents; and · amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions. Our Credit Facility, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our Credit Facility, of not less than 1.0 to 1.0. In connection with the Fifteenth Amendment, effective April 1, 2015, the Consolidated Net Debt to Consolidated EBITDAX covenant previously required by our 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 2.0 to 1.0. Additionally, our Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our Credit Facility. An acceleration of our indebtedness under our Credit Facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised and defined in the amendment to now include both secured and unsecured debt. We incurred $1,404 in fees associated with the Fifteenth Amendment. If the outstanding borrowings under our Credit Facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six -month period, (2) to submit within 30 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 30 days. Recent events related to our liquidity as discussed in “Note 2—Going concern and liquidity” have or will result in events of default under our Credit Facility. Debt issuance costs The costs that we incur to issue debt include underwriting and other professional fees. These costs are initially capitalized and are included in “Other assets” in the consolidated balance sheets. The balance of unamortized issuance costs was $18,359 and $20,937 as of December 31, 2015 and 2014, respectively. These costs are amortized as a charge to interest expense using the effective interest method. We recorded amortization of $1,921, $2,335 and $2,197 for the years ended, December 31, 2015, 2014 and 2013, respectively. Per new guidance issued in early 2015, debt issuance costs, excluding those associated with line-of-credit arrangements, will no longer be recorded in “Other assets” in the consolidated balance sheets but will be recorded as a direct deduction from the carrying value of the Senior Notes. This change in presentation will begin in 2016. See “Note 1—Nature of operations and summary of significant accounting policies” for further discussion. Capital leases In 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 $3,181 annually. Senior Note repurchases During December 2015, we repurchased approximately $42,045 of our outstanding senior notes on the open market for $9,995 in cash. As a result, we recorded a gain on extinguishment of debt of $31,590. The senior notes and notional amounts repurchased are as follows: · 9.875% senior notes due 2020 – $2,000; · 8.25% senior notes due 2021 – $15,955; · 7.625% senior notes due 2022 – $24,090.

Derivative instruments

Derivative instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative instruments	Note 7: 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. See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions. 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. As discussed in “Note 2 – Going concern and liquidity” certain events relating to our liquidity may impact our compliance under the master agreements that govern our derivative transactions. The following table summarizes our crude oil derivatives outstanding as of December 31, 2015: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Sold puts Purchased puts Sold calls Average deferred premium 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 $41.45 for 2016 as of December 31, 2015, the average realized price, and concurrently the floor price, of our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42 per barrel. In the event that prices increase above $60.00 per barrel upon settlement, 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 December 31, 2015: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 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 from 2015 through 2017 and covering 495,000 barrels of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our credit facility. As a result, we received net proceeds of $15,395 which are included in “non-hedge derivative gains (losses)” disclosed below for the year ended December 31, 2015. Effect of derivative instruments on the consolidated balance sheets All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 8 —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 December 31, 2015 As of December 31, 2014 Assets Liabilities Net value Assets Liabilities Net value Natural gas swaps $ 41,328 $ — $ 41,328 $ 32,939 $ — $ 32,939 Oil swaps — — — 23,465 — 23,465 Oil three-way collars 6,500 — 6,500 1,175 — 1,175 Oil enhanced swaps 45,516 — 45,516 100,724 — 100,724 Oil purchased and sold puts 71,052 — 71,052 93,268 — 93,268 Natural gas basis differential swaps — (1,158 ) (1,158 ) 292 (309 ) (17 ) Total derivative instruments 164,396 (1,158 ) 163,238 251,863 (309 ) 251,554 Less: Netting adjustments (1) 1,158 (1,158 ) — 232 (232 ) — Derivative instruments - current 143,737 — 143,737 179,921 (77 ) 179,844 Derivative instruments - long-term $ 19,501 $ — $ 19,501 $ 71,710 $ — $ 71,710 (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet. Derivative settlements outstanding were as follows at December 31: 2015 2014 Derivative settlements receivable included in accounts receivable $ 40,380 $ 19,678 Effect of derivative instruments on the consolidated statements of operations We discontinued hedge accounting effective April 1, 2010, and have since no longer applied hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative gains (losses)” in the consolidated statements of operations. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through AOCI and upon settlement, were reclassified from AOCI into gain from oil hedging activities which was a component of total revenues in the consolidated statements of operations. After December 31, 2013, there were no longer any deferred gains in AOCI as all the previously deferred gains (losses) had been reclassified into earnings upon the sale of the hedged production. “Non-hedge derivative gains (losses)” in the consolidated statements of operations is comprised of the following: 2015 2014 2013 Change in fair value of commodity price swaps $ (15,077 ) $ 59,627 $ (20,717 ) Change in fair value of collars 5,325 (1,597 ) (23,459 ) Change in fair value of enhanced swaps and put options (77,424 ) 172,533 186 Change in fair value of natural gas basis differential contracts (1,141 ) (1,660 ) 3,242 Receipts from (payments on) settlement of commodity price swaps 56,734 (6,607 ) 5,122 (Payments on) receipts from settlement of collars (24 ) 7,382 14,548 Receipts from settlement of enhanced swaps and put options 177,178 2,221 — Payments on settlement of natural gas basis differential contracts (283 ) (579 ) (557 ) Non-hedge derivative gains (losses) $ 145,288 $ 231,320 $ (21,635 )

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value measurements	Note 8: Fair value measurements Recurring fair value measurements Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 7—Derivative instruments”). We have no Level 1 assets or liabilities as of December 31, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of December 31, 2015 and December 31, 2014 consisted of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate. As of December 31, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts and purchased puts. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets. The fair value hierarchy for our financial assets and liabilities is shown by the following table: As of December 31, 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) $ 41,328 $ (1,158 ) $ 40,170 $ 56,696 $ (309 ) $ 56,387 Significant unobservable inputs (Level 3) 123,068 — 123,068 195,167 — 195,167 Netting adjustments (1) (1,158 ) 1,158 — (232 ) 232 — $ 163,238 $ — $ 163,238 $ 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 at December 31, 2015 and 2014 were: Net derivative assets 2015 2014 Beginning balance $ 195,167 $ 3,622 Realized and unrealized gains (losses) included in non-hedge derivative gains (losses) 105,055 180,539 Purchases — 20,609 Settlements received (177,154 ) (9,603 ) Ending balance $ 123,068 $ 195,167 Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period $ 61,260 $ 169,442 Nonrecurring fair value measurements Allocation of purchase price in business combinations. The estimated fair values of proved oil and gas properties and asset retirement obligations assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of these assumptions, they are considered Level 3 inputs under the fair value hierarchy. See “Note 4—Acquisitions and divestitures” for additional information regarding our acquisitions. Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 15.09% and 7.60%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 9 —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 third party estimates and, therefore, is classified within Level 3 of the fair value hierarchy. During the years ended December 31, 2015 and 2013, we recognized impairment losses of $6,015 and $3,490, respectively, related to our four stacked drilling rigs and drill pipe. No impairment was recognized on our drilling rigs for the year ended December 31, 2014. 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 debt at December 31, 2015 and 2014 were as follows: December 31, 2015 December 31, 2014 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 293,815 $ 75,750 $ 295,139 $ 269,091 8.25% Senior Notes due 2021 384,045 96,956 400,000 270,000 7.625% Senior Notes due 2022 530,849 120,478 554,869 379,775 Credit Facility 367,000 367,000 347,000 347,000 Other secured debt 11,981 11,981 14,957 14,957 $ 1,587,690 $ 672,165 $ 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 credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms. See “Note 1 —Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements. Concentrations of credit risk Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our 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 credit facility can be offset against amounts owed to such counterparty lender under our credit facility. As of December 31, 2015, the counterparties to our open derivative contracts consisted of seven financial institutions, of which seven were subject to our rights of offset under our 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 credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our credit facility. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting Net assets (liabilities) Derivatives (1) Amounts under credit facility Net amount As of December 31, 2015 Derivative assets $ 164,396 $ (1,158 ) $ 163,238 $ — $ (103,618 ) $ 59,620 Derivative liabilities (1,158 ) 1,158 — — — — $ 163,238 $ — $ 163,238 $ — $ (103,618 ) $ 59,620 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 credit facility. Payment on our derivative contracts could be accelerated in the event of a default on our credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $1,158 at December 31, 2015. Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions. Commodity sales to our top three purchasers accounted for the following percentages of our total commodity sales, excluding the effects of hedging activities, for the years ended December 31: 2015 2014 2013 Valero Energy Corporation 20.7 % 23.7 % 20.1 % Coffeyville Resources LLC 14.5 % 14.0 % 19.1 % Phillips 66 Company 11.8 % * * * Less than 10% If we were to lose a purchaser, we believe we are able to secure other purchasers for the commodities we produce.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Note 9: Asset retirement obligations The following table presents the balance and activity of our asset retirement obligations: For the year ended December 31, 2015 2014 Beginning balance $ 47,424 $ 55,179 Liabilities incurred in current period 1,861 5,011 Liabilities settled or disposed in current period (6,472 ) (19,184 ) Revisions in estimated cash flows 2,139 2,450 Accretion expense 3,660 3,968 Asset retirement obligations at end of period 48,612 47,424 Less current portion included in accounts payable and accrued liabilities 2,178 4,147 Asset retirement obligations, long-term $ 46,434 $ 43,277 Liabilities incurred and assumed include obligations related to new wells drilled and wells acquired during the period. Liabilities settled or disposed for the year ended December 31, 2015 increased significantly primarily due to the divestiture of certain non-strategic oil and natural gas properties sold during 2015 combined with increased plugging and abandoning activity. We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,567 and $1,568 at December 31, 2015 and 2014, respectively, and is included in “Other assets” in our consolidated balance sheets. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells. See “Note 8 —Fair value measurements” for additional information regarding fair value measurements.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income taxes	Note 10: Income taxes Income tax (benefit) expense from continuing operations consists of the following for the years ended December 31: 2015 2014 2013 Current income taxes Federal $ (21 ) $ (22 ) $ (29 ) State 195 574 1,144 Total current income taxes 174 552 1,115 Deferred income taxes Federal (161,879 ) 115,699 30,327 State (15,514 ) 8,192 1,407 Total deferred income taxes (177,393 ) 123,891 31,734 Income tax (benefit) expense $ (177,219 ) $ 124,443 $ 32,849 A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate is as follows for the years ended December 31: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal benefit 3.1 % 2.6 % 3.8 % Statutory depletion — (0.2 )% (0.7 )% Valuation allowance (26.5 )% — (1.7 )% Other, net 0.1 % (0.1 )% 0.7 % Effective tax rate 11.7 % 37.3 % 37.1 % Components of the deferred tax assets and liabilities are as follows at December 31: 2015 2014 Deferred tax assets related to Asset retirement obligations $ 14,669 $ 12,988 Accrued expenses, allowance and other 11,564 15,057 Property and equipment 259,096 — Inventories 372 — Net operating loss carryforwards Federal 154,265 121,556 State 21,466 15,052 Statutory depletion carryforwards 3,962 3,833 Alternative minimum tax credit carryforwards 308 308 465,702 168,794 Less valuation allowance (411,147 ) (10,499 ) Deferred tax asset 54,555 158,295 Deferred tax liabilities related to Derivative instruments (54,555 ) (88,910 ) Property and equipment — (245,629 ) Inventories — (1,243 ) Deferred tax liability (54,555 ) (335,782 ) Net deferred tax liability — (177,487 ) Less net current deferred tax liability (53,914 ) (60,728 ) Long-term deferred tax asset (liability) $ 53,914 $ (116,759 ) Deferred tax asset valuation allowance. The ultimate realization of our deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. We assess the realizability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of our deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. We evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. A significant item of objective negative evidence considered was our cumulative historical three year pre-tax loss and our net deferred tax asset position at December 31, 2015, driven primarily by the full cost ceiling impairments recognized during the third quarter and fourth quarter of 2015, which limits the ability to consider other subjective evidence such as the Company’s anticipated future growth. We concluded in the third quarter of 2015 it was more likely than not that our deferred tax assets would not be realized and recorded additional valuation allowance totaling approximately $225,000 (including approximately $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014) against our net deferred tax asset of as of September 30, 2015. The valuation allowance was further increased by $176,000 to $411,147 against our net deferred tax assets as of December 31, 2015, reducing our net deferred tax assets to zero. We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against its net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit. Net operating loss carryforwards. We have federal net operating loss carryforwards of approximately $441,000 at December 31, 2015, which will expire between 2028 and 2035 if not utilized in earlier periods. At December 31, 2015, we have state net operating loss carryforwards of approximately $530,000, which will expire between 2016 and 2035 if not utilized in earlier periods. In addition, at December 31, 2015 we had federal percentage depletion carryforwards of approximately $11,000, which are not subject to expiration. Our ability to utilize our loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. We do not have a Section 382 limitation on our ability to utilize our U.S. loss carryforwards as of December 31, 2015. In 2016, however, certain restructuring activities being pursued could impact the ultimate realization of our net operating losses and our tax basis. Future equity transactions involving the Company or 5% of our shareholders (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes resulting in a Section 382 limitation in 2016 on the annual utilization of our loss carryforwards. Filing for protection under Chapter 11 of the U.S. Bankruptcy Code or a Section 382 limitation might cause our tax attributes to be reduced and/or subject to annual utilization limits. A significant portion of our NOL may be offset by tax gains or cancellation of debt.

Stock-based compensation

Stock-based compensation	12 Months Ended
	Dec. 31, 2015
Share Based Compensation [Abstract]
Stock-based compensation	Note 11: Stock-based compensation Phantom Stock Plan and Restricted Stock Unit Plan Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date. Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. 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. Although the Phantom Plan and RSU Plan both remain in effect, we do not expect to make any further awards under those plans. A summary of our phantom stock and RSU activity during the three years ended December 31, 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 Vest date fair value (per share) (per share) Unvested and outstanding at January 1, 2013 $ 16.87 84,764 $ 17.12 151,909 Granted $ — — $ 12.45 291,253 Vested $ 16.20 (21,260 ) $ 273 $ 17.12 (50,246 ) $ 626 Forfeited $ 17.57 (10,342 ) $ 14.27 (67,619 ) Unvested and outstanding at December 31, 2013 $ 17.01 53,162 $ 13.53 325,297 Granted $ — — $ 8.52 504,752 Vested $ 12.61 (22,041 ) $ 212 $ 13.96 (118,400 ) $ 1,094 Forfeited $ 19.95 (7,942 ) $ 9.85 (142,489 ) Unvested and outstanding at December 31, 2014 $ 20.18 23,179 $ 9.91 569,160 Granted $ — — $ 14.88 59,571 Vested $ 24.48 (6,456 ) $ 25 $ 10.73 (216,941 ) $ 855 Forfeited $ 18.33 (6,104 ) $ 9.56 (141,904 ) Unvested and outstanding at December 31, 2015 $ 18.62 10,619 $ 10.53 269,886 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 December 31, 2015 is $0.00. The weighted average period until all remaining phantom shares and RSUs vest is 0.7 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 accrue for the cost of each annual increment over the period service is required to vest. We awarded $3,297 of cash incentive awards in 2015, and recorded compensation expense of $610 for the year ended December 31, 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 Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan. The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards). The Time Vested awards vest in equal annual installments over the five -year vesting period, but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date. 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. Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the remaining number of Performance Vested shares outstanding were reallocated among five targets for vesting. Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, as Time Vested awards; and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. As a result of these modifications, vesting requirements for all remaining Performance Vested awards are set at the following levels: Return on investment target Shares vested 175% per share 33 % of shares multiplied by the Vesting Fraction 200% per share 33 % of shares multiplied by the Vesting Fraction 250% per share 34 % of shares multiplied by the Vesting Fraction The modifications above changed the classification of the canceled and reissued awards from equity to liability instruments. The modifications in 2014 and 2013 both resulted in estimated incremental compensation cost of $8,536 and $4,322, which will be recognized over the remaining requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and is adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited. A combined income and market valuation methodology was used to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2015, 2014, and 2013 was considered to be equal to the estimated fair value of our common equity per share, net of a discount for lack of marketability of 25%, 20%, and 17%, respectively. A control discount was not applied to the valuation pursuant to guidance released by the AICPA in 2013 that discourages incorporating a control premium in the enterprise value used in valuing minority interest securities within an enterprise, except to the extent that such a premium reflects improvements to the business that a market participant would expect under current ownership. The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows: 2015 2014 2013 Risk free interest rate 0.71 % to 1.44 % 0.25 % to 1.48 % 0.16 % to 2.46 % Expected volatility 71 % to 81 % 52 % to 56 % 38 % to 39 % Expected life 3 years 4 years 5 years Expected dividends $ — $ — $ — Our expected volatility was calculated based on the average of the historical stock price volatility and the volatility implicit in the prices of the options or other traded financial instruments of our peer group. Our peer group consisted of the following oil and natural gas exploration and production companies in 2015: Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Resolute Energy Corporation, Bonanza Creek Energy, Inc. and Newfield Exploration Co. Our peer group in 2014 consisted of Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Pioneer Natural Resources Co., Resolute Energy Corporation, Sandridge Energy, Inc., Whiting Petroleum Corp. and Newfield Exploration Co. A summary of our Time and Performance award activity during the three years ended December 31, 2015 is presented in the following table: 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, 2013 $ 651.97 9,481 $ 298.15 55,824 Granted $ 626.02 2,839 $ 181.59 5,217 Vested $ 662.55 (2,509 ) $ 1,556 $ — — Forfeited $ 618.87 (1,734 ) $ 340.23 (3,171 ) Modified $ 626.00 11,169 $ 324.47 (11,169 ) Unvested and outstanding at December 31, 2013 $ 634.67 19,246 $ 307.45 46,701 Granted $ 818.50 5,245 $ 204.90 10,033 Vested $ 643.55 (4,951 ) $ 4,118 $ — — Forfeited $ 631.54 (3,045 ) $ 264.54 (8,452 ) Modified $ 969.00 9,339 $ 296.69 (9,339 ) Unvested and outstanding at December 31, 2014 $ 791.52 25,834 $ 292.92 38,943 Granted $ 533.80 610 $ 113.90 599 Vested $ 775.17 (8,468 ) $ 4,497 $ — — Forfeited $ 774.21 (3,997 ) $ 323.53 (11,094 ) Unvested and outstanding at December 31, 2015 $ 795.13 13,979 $ 278.97 28,448 During 2015, 2014, and 2013, respectively, we repurchased and canceled 5,725, 2,025, and 1,025 vested shares and we expect to repurchase approximately 2,355 restricted shares vesting during the next twelve months. Based on an estimated fair value of $18.70 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $261 as of December 31, 2015. Stock-based compensation cost A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31: 2015 2014 2013 Stock-based compensation cost $ (2,169 ) $ 6,235 $ 7,819 Less: stock-based compensation cost capitalized 229 (2,346 ) (2,345 ) Stock-based compensation (credit) expense $ (1,940 ) $ 3,889 $ 5,474 Recognized tax (expense) benefit associated with stock-based compensation $ (229 ) $ 1,452 $ 2,031 Expense during 2015 was a credit as a result forfeitures and the reduction in fair value of our liability-based awards due to depressed commodity prices. Payments for stock-based compensation were $3,991, $2,995, and $1,533 during 2015, 2014, and 2013, respectively. As of December 31, 2015 and 2014, accrued payroll and benefits payable included $81 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $4,281 as of December 31, 2015 is expected to be recognized over a weighted-average period of 1.7 years.

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2015
Stockholders Equity Note [Abstract]
Stockholders' equity	Note 12: Stockholders’ equity Common Stock Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to two existing stockholders. On January 13, 2014, CHK Energy Holdings Inc. (“CHK Energy Holdings”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The 279,999 class D shares and one class G share owned by CHK Energy Holdings automatically converted to class A common stock and all associated rights with the class D and class G common stock were terminated. All remaining shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”). Holders of class B and C common stock have the right, in aggregate, to designate three directors. Holders of class E common stock have the right to designate two directors. The class B, E, F and G common stock carry the following additional voting and consent rights: · So long as the class B holders own 80% or more of the common stock they owned as of April 12, 2010, the closing date of our initial Stockholders Agreement (the “Original Date”), and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Original Date. · In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock. · Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO. · Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO. The rights and preferences of a holder of class B, C, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock. Stockholders Agreement Effective April 12, 2010, we implemented a Stockholders Agreement to provide for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our Senior Notes. The Stockholders Agreement was amended and restated on January 12, 2014 in conjunction with the sale of Chesapeake’s ownership interest in us to Healthcare of Ontario Pension Plan Trust Fund. Our Stockholders Agreement, as amended, also provides for the following stockholder-specific rights or restrictions: · Prior to a Qualified IPO, Altoma Energy GP (“Altoma”) will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer Investments, L.L.C. (“Fischer”) votes for such approval. · Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock. · CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”). · Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions. · Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement. · Either (i) CCMP or (ii) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met. · At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO. · At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer. With the exception of registration rights, the rights and preferences of a stockholder under the amended and restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock. Summary of changes in common stock The following is a summary of the changes in our common shares outstanding during the years ended December 31, 2015, 2014 and 2013: Common Stock Class A Class B Class C Class D Class E Class F Class G Total Shares issued at January 1, 2013 67,991 357,882 209,882 279,999 504,276 1 3 1,420,034 Restricted stock issuance 8,056 — — — — — — 8,056 Restricted stock repurchased (1,025 ) — — — — — — (1,025 ) Restricted stock forfeited (4,905 ) — — — — — — (4,905 ) Shares issued at December 31, 2013 70,117 357,882 209,882 279,999 504,276 1 3 1,422,160 Stock transfers (1) 293,023 (13,023 ) — (279,999 ) — — (1 ) — Restricted stock issuance 15,278 — — — — — — 15,278 Restricted stock repurchased (2,025 ) — — — — — — (2,025 ) Restricted stock forfeited (11,497 ) — — — — — — (11,497 ) Shares issued at December 31, 2014 364,896 344,859 209,882 — 504,276 1 2 1,423,916 Restricted stock issuance 1,209 — — — — — — 1,209 Restricted stock repurchased (5,725 ) — — — — — — (5,725 ) Restricted stock forfeited (15,091 ) — — — — — — (15,091 ) Shares issued at December 31, 2015 345,289 344,859 209,882 — 504,276 1 2 1,404,309 (1) In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

Retirement benefits

Retirement benefits	12 Months Ended
	Dec. 31, 2015
Compensation And Retirement Disclosure [Abstract]
Retirement benefits	Note 13: Retirement benefits We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2015, 2014 and 2013. At December 31, 2015, 2014, and 2013, there were 395, 625, and 585 employees, respectively, participating in the plan. Our contribution expense was $2,363, $3,592, and $3,621 for the years ended December 31, 2015, 2014 and 2013, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and contingencies	Note 14: Commitments and contingencies Letters of Credit. Standby letters of credit (“Letters”) available under our 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 an outstanding amount of $828 and $920 as of December 31, 2015 and 2014, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2015, 2014, or 2013. Commitments. We have four long-term contracts with four different suppliers to purchase CO 2 As of December 31, 2015, we were purchasing approximately 49 MMcf/d of CO 2 Based on current prices, our estimated minimum purchase obligations under our CO 2 2016 $ 2,193 2017 1,290 2018 1,289 2019 1,290 2020 1,289 2021 and thereafter 3,066 $ 10,417 In addition to our CO 2 Operating Leases. We rent equipment used on our oil and natural gas properties and have operating lease agreements for CO 2 2 2 As of December 31, 2015, total remaining payments associated with our operating leases were: 2016 $ 1,095 2017 1,095 2018 1,093 2019 1,088 2020 1,055 2021 and thereafter 1,018 $ 6,444 Other Contingencies. We have entered into change of control severance agreements under which our officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a period of months as calculated under the terms of the agreement and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to their termination date, plus (B) the officer’s bonus for the full year in which the termination date occurred. As of December 31, 2015, the maximum amount payable under these agreements in the event of a change in control that results in our officers being terminated is $14,532. 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, but the motion for class certification and responsive briefs were filed in the fourth quarter of 2015, and we expect a hearing on class certification to be held in the second quarter of 2016. 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, 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, filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the 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. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case. Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, 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 , 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 defendants, which is still pending. In a case with similar claims, also pending in the United States District Court for the Northern District of Oklahoma, the court determined the Bureau of Indian Affairs violated the National Environmental Protection act by not conducting environmental assessments before granting leases and permits on Osage tribal lands in Osage County, Oklahoma, and therefore found both the lease and the two related drilling permits void ab initio. At this time, discovery has commenced and is ongoing. A class has not been certified. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case. Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma (“West Case”), alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in Cleveland, Lincoln, McClain, Okfuskee, Oklahoma, Pontotoc, Pottawatomie and Seminole Counties, Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced or triggered earthquakes in the Class Area. The plaintiffs are asking the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through a future date defined as the time at which the court determines there is no longer a risk our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs have not asked for damages related to actual property damage which may have occurred. We have responded to the 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 West 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, and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case. 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.

Oil and natural gas activities

Oil and natural gas activities	12 Months Ended
	Dec. 31, 2015
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Abstract]
Oil and natural gas activities	Note 15: Oil and natural gas activities Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31: 2015 2014 2013 Property acquisition costs Proved properties $ 1,192 $ 3,496 $ 69,962 Unproved properties 24,735 84,938 145,853 Total acquisition costs 25,927 88,434 215,815 Development costs 150,261 561,578 376,394 Exploration costs (1) 33,091 90,146 77,507 Total $ 209,279 $ 740,158 $ 669,716 (1) Includes $515, $152, and $37,344 of EOR costs in 2015, 2014, and 2013, respectively. Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows for the years ended December 31: 2015 2014 2013 DD&A $ 204,692 $ 231,761 $ 179,734 DD&A per BOE: $ 20.07 $ 21.10 $ 18.45 Oil and natural gas properties not subject to amortization consist of the cost of unevaluated properties and seismic costs associated with specific unevaluated properties. Of the $66,905 of unproved property costs at 2015 being excluded from the amortization base, $24,587, $37,846, and $4,472 were incurred in 2015, 2014, and 2013, respectively. We expect to complete our evaluation for the majority of these costs relating to non-EOR properties within the next two to five years.

Disclosures about oil and natur

Disclosures about oil and natural gas activities (unaudited)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Disclosures about oil and natural gas activities (unaudited)	Note 16: Disclosures about oil and natural gas activities (unaudited) The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2015 are as follows: Oil (MBbls) Natural gas (MMcf) Natural gas liquids (MBbls) Total (MBoe) Proved developed and undeveloped reserves As of January 1, 2013 92,047 257,115 11,195 146,095 Purchase of minerals in place 3,283 3,618 1,059 4,945 Sales of minerals in place (5,174 ) (9,708 ) (324 ) (7,116 ) Extensions and discoveries 11,556 62,412 3,127 25,085 Revisions (1) (7,772 ) 9,735 1,479 (4,671 ) Improved recoveries 3,879 — — 3,879 Production (5,006 ) (20,250 ) (1,361 ) (9,742 ) Balance at December 31, 2013 92,813 302,922 15,175 158,475 Purchase of minerals in place 276 859 55 474 Sales of minerals in place (8,539 ) (79,579 ) (1,959 ) (23,761 ) Extensions and discoveries 12,776 56,159 3,405 25,541 Revisions (1) (3,356 ) (11,957 ) 1,741 (3,608 ) Improved recoveries 13,254 — — 13,254 Production (5,977 ) (20,648 ) (1,564 ) (10,982 ) Balance at December 31, 2014 101,247 247,756 16,853 159,393 Purchase of minerals in place 38 1,120 46 271 Sales of minerals in place (2,225 ) (3,656 ) (117 ) (2,951 ) Extensions and discoveries 3,651 13,759 1,096 7,040 Revisions (1) (19,840 ) (61,973 ) (4,257 ) (34,426 ) Improved recoveries (2) 36,414 — — 36,414 Production (5,519 ) (18,788 ) (1,550 ) (10,200 ) Balance at December 31, 2015 113,766 178,218 12,071 155,541 Proved developed reserves: January 1, 2013 54,737 185,826 9,218 94,926 December 31, 2013 56,360 196,920 11,484 100,664 December 31, 2014 54,862 158,265 11,787 93,027 December 31, 2015 40,300 132,323 9,169 71,524 Proved undeveloped reserves: January 1, 2013 37,310 71,289 1,977 51,169 December 31, 2013 36,453 106,002 3,691 57,811 December 31, 2014 46,385 89,491 5,066 66,366 December 31, 2015 73,466 45,895 2,902 84,017 (1) The downward revision in our reserves during 2015 was primarily due to the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. The downward revision in our reserves during 2014 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and a decline in the estimated sales margin on natural gas. The downward revision in our reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame and to negative technical revisions. The 2013 downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas. (2) Improved recoveries in 2015 resulted from the addition of reserves from remaining future phases of CO 2 The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance. We believe that, in reviewing the information that follows, the following factors should be taken into account: · future costs and sales prices will probably differ from those required to be used in these calculations; · actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations; · a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and · future net revenues may be subject to different rates of income taxation. Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 7 —Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions. In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the year ended December 31, 2015 2014 2013 Future cash flows $ 6,327,363 $ 11,275,090 $ 10,660,532 Future production costs (2,670,692 ) (3,605,107 ) (3,841,723 ) Future development and abandonment costs (1,536,063 ) (1,726,955 ) (1,506,585 ) Future income tax provisions (89,999 ) (1,487,121 ) (1,328,925 ) Net future cash flows 2,030,609 4,455,907 3,983,299 Less effect of 10% discount factor (1,345,920 ) (2,561,207 ) (2,239,527 ) Standardized measure of discounted future net cash flows $ 684,689 $ 1,894,700 $ 1,743,772 The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the year ended December 31, 2015 2014 2013 Beginning of year $ 1,894,700 $ 1,743,772 $ 1,523,681 Sale of oil and natural gas produced, net of production costs (196,319 ) (502,928 ) (418,224 ) Net changes in prices and production costs (1) (2,230,601 ) 116,977 172,975 Extensions and discoveries 101,384 286,500 514,743 Improved recoveries 524,436 148,673 79,589 Changes in future development costs 204,199 (91,027 ) (236,121 ) Development costs incurred during the period that reduced future development costs 80,103 316,490 110,354 Revisions of previous quantity estimates (1) (495,794 ) (40,481 ) (95,855 ) Purchases and sales of reserves in place, net (47,079 ) (278,825 ) (20,021 ) Accretion of discount 237,134 223,324 152,830 Net change in income taxes (1) 605,766 (46,584 ) (60,981 ) Changes in production rates and other 6,760 18,809 20,802 End of year $ 684,689 $ 1,894,700 $ 1,743,772 (1) Amounts in 2015 are primarily the result of the decrease in SEC pricing, which resulted in a loss of reserves as extraction has become uneconomic, lower margins on existing reserves and a decrease in taxes as a result of the lower margins. The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation. 2015 2014 2013 Oil (per Bbl) $ 50.28 $ 94.99 $ 96.78 Natural gas (per Mcf) $ 2.58 $ 4.35 $ 3.67 Natural gas liquids (per Bbl) $ 15.84 $ 36.10 $ 32.53

Nature of operations and summ24

Nature of operations and summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
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.
Principles of consolidation	Principles of consolidation The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.
Use of estimates	Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.
Reclassifications	Reclassifications Certain reclassifications have been made to prior period financial statements to conform to current period presentation. 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. As of December 31, 2015, cash with a recorded balance totaling $13,507 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. We are not party to any valid blocked account agreements with respect to any material amount of cash.
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. Accounts receivable consisted of the following at December 31: 2015 2014 Joint interests $ 14,149 $ 30,648 Accrued commodity sales 21,645 45,667 Derivative settlements 40,380 19,678 Other 3,329 2,738 Allowance for doubtful accounts (503 ) (287 ) $ 79,000 $ 98,444
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. We recorded a lower of cost or market adjustment of $10,192 on our equipment inventory for the year ended December 31, 2015. The adjustment was recorded to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity decreased in the 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 consisted of the following at December 31: 2015 2014 Equipment inventory $ 11,470 $ 24,169 Commodities 1,698 2,575 Inventory valuation allowance (839 ) (1,187 ) $ 12,329 $ 25,557
Property and equipment	Property and equipment Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently. Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows: Furniture and fixtures 10 years Automobiles and trucks 5 years Machinery and equipment 10 — 20 years Office and computer equipment 5 — 10 years Building and improvements 10 — 40 years
Oil and natural gas properties	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 acquisition, 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, lease bonus payments, 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. As of December 31, 2015, unevaluated oil and natural gas properties include $60,031 of capital costs incurred for undeveloped acreage and $6,874 for wells and facilities in progress pending determination. As of December 31, 2014, work in progress costs included $190,356 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO 2 2 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 December 31, 2015, 2014, and 2013 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). Due to the substantial decline of commodity prices that began in late 2014 and continued through 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 year ended December 31, 2015 of $1,491,129. Further write-downs may occur if prices remain at current levels or continue to decline subsequent to December 31, 2015. 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. We recorded impairment losses of $6,015, nil and $3,490 related to certain of our drilling rigs during the years ended December 31, 2015, 2014 and 2013, respectively. The drilling rigs were previously classified as held for sale but were reclassified to property and equipment in late 2013 when the ultimate disposal became uncertain. 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 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.
Income taxes	Income taxes Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized. See “Note 10—Income taxes” for further discussion of our valuation allowance. If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2015 and 2014, we have no uncertain tax positions and as such have not recorded a liability or accrued interest or penalties related to uncertain tax positions. We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2008 through 2015 tax years generally remain subject to examination by federal and state tax authorities.
Derivative transactions	Derivative transactions We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in “Non-hedge derivative gains (losses)” in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities. Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and was reclassified into income as the hedged transactions occurred. As of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings. We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 7 —Derivative instruments” for additional information regarding our derivative transactions.
Fair value measurements	Fair value measurements Fair value is defined by the Financial Accounting Standards Board (“FASB”) as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, our drilling rigs which we have impaired and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 8 —Fair value measurements” for additional information regarding our fair value measurements.
Valuation of business combinations	Valuation of business combinations In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting.
Asset retirement obligations	Asset retirement obligations We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in “Depreciation, depletion and amortization” in our consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 9 —Asset retirement obligations” for additional information regarding our asset retirement obligations.
Environmental liabilities	Environmental liabilities We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2015 and 2014, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.
Revenue recognition	Revenue recognition Sales of oil, natural gas and NGLs are recorded when title of production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products are recognized at the time of delivery of materials.
Gas balancing	Gas balancing In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2015 and, 2014 our aggregate imbalance due to under production was approximately 0 MMcf and 2,005 MMcf, respectively. As of December 31, 2015 and 2014, our aggregate imbalance due to over production was approximately 1,253 MMcf and 1,276 MMcf, respectively, and a liability for gas imbalances of $1,303 and $1,110, respectively, was included in accounts payable and accrued liabilities.
Stock-based compensation	Stock-based compensation Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan. The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting. We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted. The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. See “Note 11 —Stock-based compensation” for additional information relating to stock-based compensation.
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 $10,028 of expenses for cost reduction initiatives for the year ended December 31, 2015, is $7,757 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 issued accounting pronouncements	Recently adopted accounting pronouncements Other Expenses . In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations. Recently issued accounting pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. 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 permitted only for fiscal years beginning after December 31, 2016, and interim periods thereafter. 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 were not affected by the amendment. This guidance, which was effective and adopted by us in the first quarter of 2016, only affects the presentation of our consolidated balance sheets and does not have a material impact on our consolidated financial statements. 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 beginning 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 November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying component of a jurisdiction) to be presented as a net current asset or liability and net noncurrent asset or liability. This requires a jurisdiction-by-jurisdiction analysis based on the classification of the assets and liabilities to which the underlying temporary differences relate, or, in the case of loss or credit carryforwards, based on the period in which the attribute is expected to be realized. Any valuation allowance is then required to be allocated on a pro rata basis, by jurisdiction, between current and noncurrent deferred tax assets. To simplify presentation, the new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. Importantly, the guidance does not change the existing requirement that only permits offsetting within a jurisdiction – that is, companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. The guidance is effective for public business entities in fiscal periods beginning after December 15, 2016, and interim periods thereafter. We do not expect this guidance to have a significant impact on our consolidated financial statements, other than balance sheet reclassifications. In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations. In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.
Derivatives, Offsetting Fair Value Amounts	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

Nature of operations and summ25

Nature of operations and summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Components of accounts receivable	Accounts receivable consisted of the following at December 31: 2015 2014 Joint interests $ 14,149 $ 30,648 Accrued commodity sales 21,645 45,667 Derivative settlements 40,380 19,678 Other 3,329 2,738 Allowance for doubtful accounts (503 ) (287 ) $ 79,000 $ 98,444
Components of inventory	Inventories consisted of the following at December 31: 2015 2014 Equipment inventory $ 11,470 $ 24,169 Commodities 1,698 2,575 Inventory valuation allowance (839 ) (1,187 ) $ 12,329 $ 25,557
Schedule Of Estimated Useful Lives for Property and Equipment	Estimated useful lives of our assets are as follows: Furniture and fixtures 10 years Automobiles and trucks 5 years Machinery and equipment 10 — 20 years Office and computer equipment 5 — 10 years Building and improvements 10 — 40 years

Supplemental disclosures to t26

Supplemental disclosures to the consolidated statements of cash flows (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental disclosures to the consolidated statements of cash flows	Supplemental disclosures to the consolidated statements of cash flows are presented below: Year ended December 31, 2015 2014 2013 Net cash provided by operating activities included: Cash payments for interest $ 116,379 $ 112,196 $ 107,122 Interest capitalized (9,670 ) (13,491 ) (15,995 ) Cash payments for interest, net of amounts capitalized $ 106,709 $ 98,705 $ 91,127 Cash payments for income taxes $ 640 591 641 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 4,000 $ 7,461 $ 9,036 Change in accrued oil and gas capital expenditures $ (105,312 ) $ 43,971 $ 27,875

Acquisitions and divestitures (

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Purchase price allocation	The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013. Consideration paid Cash, net of purchase price adjustments $ 153,858 Fair value of identifiable assets acquired and liabilities assumed Oil and natural gas properties Proved $ 67,275 Unevaluated 87,663 Asset retirement obligations (1,080 ) Fair value of net identifiable assets acquired $ 153,858
Unaudited pro forma information	The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects. Year ended December 31, 2013 Revenues $ 690,564 Operating expenses $ 448,751 Net income $ 76,552

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Components of Property and Equipment	Major classes of property and equipment consist of the following at December 31: 2015 2014 Furniture and fixtures $ 2,518 $ 2,488 Automobiles and trucks 10,689 13,721 Machinery and equipment 55,963 57,922 Office and computer equipment 19,993 18,305 Building and improvements 25,534 29,322 114,697 121,758 Less accumulated depreciation and amortization 75,041 64,310 39,656 57,448 Land 9,306 9,113 $ 48,962 $ 66,561

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Components of debt	As of the dates indicated, debt consists of the following: December 31, 2015 2014 9.875% Senior Notes due 2020, net of discount of $4,185 and $4,861, respectively $ 293,815 $ 295,139 8.25% Senior Notes due 2021 384,045 400,000 7.625% Senior Notes due 2022, including premium of $4,939 and $4,869, respectively 530,849 554,869 Credit Facility 367,000 347,000 Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.16% to 5.46%, due August 2021 through December 2028; collateralized by real property 10,182 10,705 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95%, due January 2016 through February 2018; collateralized by automobiles, machinery and equipment 1,799 4,252 Capital lease obligations 19,437 21,837 Total debt, net 1,607,127 1,633,802 Less current portion (1) 1,607,127 5,377 Total long-term debt, net $ — $ 1,628,425
Maturities of debt and capital leases, excluding premium or discount on our Senior Notes	Absent any acceleration of our debt resulting from defaults, the maturities of debt and capital leases, and excluding premiums or discounts on our Senior Notes, would be as follows as of December 31, 2015: 2016 $ 4,409 2017 370,600 2018 3,302 2019 12,328 2020 298,687 2021 and thereafter 917,047 $ 1,606,373

Derivative instruments (Tables)

Derivative instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Outstanding derivative instruments	The following table summarizes our crude oil derivatives outstanding as of December 31, 2015: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Sold puts Purchased puts Sold calls Average deferred premium 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 $41.45 for 2016 as of December 31, 2015, the average realized price, and concurrently the floor price, of our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42 per barrel. In the event that prices increase above $60.00 per barrel upon settlement, 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 December 31, 2015: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 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 December 31, 2015 As of December 31, 2014 Assets Liabilities Net value Assets Liabilities Net value Natural gas swaps $ 41,328 $ — $ 41,328 $ 32,939 $ — $ 32,939 Oil swaps — — — 23,465 — 23,465 Oil three-way collars 6,500 — 6,500 1,175 — 1,175 Oil enhanced swaps 45,516 — 45,516 100,724 — 100,724 Oil purchased and sold puts 71,052 — 71,052 93,268 — 93,268 Natural gas basis differential swaps — (1,158 ) (1,158 ) 292 (309 ) (17 ) Total derivative instruments 164,396 (1,158 ) 163,238 251,863 (309 ) 251,554 Less: Netting adjustments (1) 1,158 (1,158 ) — 232 (232 ) — Derivative instruments - current 143,737 — 143,737 179,921 (77 ) 179,844 Derivative instruments - long-term $ 19,501 $ — $ 19,501 $ 71,710 $ — $ 71,710 (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
Derivative settlements outstanding	Derivative settlements outstanding were as follows at December 31: 2015 2014 Derivative settlements receivable included in accounts receivable $ 40,380 $ 19,678
Non-hedge derivative gains (losses) in the consolidated statements of operations	“Non-hedge derivative gains (losses)” in the consolidated statements of operations is comprised of the following: 2015 2014 2013 Change in fair value of commodity price swaps $ (15,077 ) $ 59,627 $ (20,717 ) Change in fair value of collars 5,325 (1,597 ) (23,459 ) Change in fair value of enhanced swaps and put options (77,424 ) 172,533 186 Change in fair value of natural gas basis differential contracts (1,141 ) (1,660 ) 3,242 Receipts from (payments on) settlement of commodity price swaps 56,734 (6,607 ) 5,122 (Payments on) receipts from settlement of collars (24 ) 7,382 14,548 Receipts from settlement of enhanced swaps and put options 177,178 2,221 — Payments on settlement of natural gas basis differential contracts (283 ) (579 ) (557 ) Non-hedge derivative gains (losses) $ 145,288 $ 231,320 $ (21,635 )

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value hierarchy for financial instruments measured at fair value on a recurring basis	The fair value hierarchy for our financial assets and liabilities is shown by the following table: As of December 31, 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) $ 41,328 $ (1,158 ) $ 40,170 $ 56,696 $ (309 ) $ 56,387 Significant unobservable inputs (Level 3) 123,068 — 123,068 195,167 — 195,167 Netting adjustments (1) (1,158 ) 1,158 — (232 ) 232 — $ 163,238 $ — $ 163,238 $ 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 at December 31, 2015 and 2014 were: Net derivative assets 2015 2014 Beginning balance $ 195,167 $ 3,622 Realized and unrealized gains (losses) included in non-hedge derivative gains (losses) 105,055 180,539 Purchases — 20,609 Settlements received (177,154 ) (9,603 ) Ending balance $ 123,068 $ 195,167 Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period $ 61,260 $ 169,442
Fair value of other financial instruments	The carrying value and estimated fair value of our debt at December 31, 2015 and 2014 were as follows: December 31, 2015 December 31, 2014 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 293,815 $ 75,750 $ 295,139 $ 269,091 8.25% Senior Notes due 2021 384,045 96,956 400,000 270,000 7.625% Senior Notes due 2022 530,849 120,478 554,869 379,775 Credit Facility 367,000 367,000 347,000 347,000 Other secured debt 11,981 11,981 14,957 14,957 $ 1,587,690 $ 672,165 $ 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 credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our credit facility. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting Net assets (liabilities) Derivatives (1) Amounts under credit facility Net amount As of December 31, 2015 Derivative assets $ 164,396 $ (1,158 ) $ 163,238 $ — $ (103,618 ) $ 59,620 Derivative liabilities (1,158 ) 1,158 — — — — $ 163,238 $ — $ 163,238 $ — $ (103,618 ) $ 59,620 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
Percentages of Total Commodity Sales Excluding Effects of Hedging Activities	Commodity sales to our top three purchasers accounted for the following percentages of our total commodity sales, excluding the effects of hedging activities, for the years ended December 31: 2015 2014 2013 Valero Energy Corporation 20.7 % 23.7 % 20.1 % Coffeyville Resources LLC 14.5 % 14.0 % 19.1 % Phillips 66 Company 11.8 % * *

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	The following table presents the balance and activity of our asset retirement obligations: For the year ended December 31, 2015 2014 Beginning balance $ 47,424 $ 55,179 Liabilities incurred in current period 1,861 5,011 Liabilities settled or disposed in current period (6,472 ) (19,184 ) Revisions in estimated cash flows 2,139 2,450 Accretion expense 3,660 3,968 Asset retirement obligations at end of period 48,612 47,424 Less current portion included in accounts payable and accrued liabilities 2,178 4,147 Asset retirement obligations, long-term $ 46,434 $ 43,277

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of income tax (benefit) expense from continuing operations	Income tax (benefit) expense from continuing operations consists of the following for the years ended December 31: 2015 2014 2013 Current income taxes Federal $ (21 ) $ (22 ) $ (29 ) State 195 574 1,144 Total current income taxes 174 552 1,115 Deferred income taxes Federal (161,879 ) 115,699 30,327 State (15,514 ) 8,192 1,407 Total deferred income taxes (177,393 ) 123,891 31,734 Income tax (benefit) expense $ (177,219 ) $ 124,443 $ 32,849
Income tax rate reconciliation	A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate is as follows for the years ended December 31: 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal benefit 3.1 % 2.6 % 3.8 % Statutory depletion — (0.2 )% (0.7 )% Valuation allowance (26.5 )% — (1.7 )% Other, net 0.1 % (0.1 )% 0.7 % Effective tax rate 11.7 % 37.3 % 37.1 %
Components of deferred tax assets and liabilities	Components of the deferred tax assets and liabilities are as follows at December 31: 2015 2014 Deferred tax assets related to Asset retirement obligations $ 14,669 $ 12,988 Accrued expenses, allowance and other 11,564 15,057 Property and equipment 259,096 — Inventories 372 — Net operating loss carryforwards Federal 154,265 121,556 State 21,466 15,052 Statutory depletion carryforwards 3,962 3,833 Alternative minimum tax credit carryforwards 308 308 465,702 168,794 Less valuation allowance (411,147 ) (10,499 ) Deferred tax asset 54,555 158,295 Deferred tax liabilities related to Derivative instruments (54,555 ) (88,910 ) Property and equipment — (245,629 ) Inventories — (1,243 ) Deferred tax liability (54,555 ) (335,782 ) Net deferred tax liability — (177,487 ) Less net current deferred tax liability (53,914 ) (60,728 ) Long-term deferred tax asset (liability) $ 53,914 $ (116,759 )

Stock-based compensation (Table

Stock-based compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share Based Compensation [Abstract]
Rollforward of unvested stock-based compensation awards	A summary of our phantom stock and RSU activity during the three years ended December 31, 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 Vest date fair value (per share) (per share) Unvested and outstanding at January 1, 2013 $ 16.87 84,764 $ 17.12 151,909 Granted $ — — $ 12.45 291,253 Vested $ 16.20 (21,260 ) $ 273 $ 17.12 (50,246 ) $ 626 Forfeited $ 17.57 (10,342 ) $ 14.27 (67,619 ) Unvested and outstanding at December 31, 2013 $ 17.01 53,162 $ 13.53 325,297 Granted $ — — $ 8.52 504,752 Vested $ 12.61 (22,041 ) $ 212 $ 13.96 (118,400 ) $ 1,094 Forfeited $ 19.95 (7,942 ) $ 9.85 (142,489 ) Unvested and outstanding at December 31, 2014 $ 20.18 23,179 $ 9.91 569,160 Granted $ — — $ 14.88 59,571 Vested $ 24.48 (6,456 ) $ 25 $ 10.73 (216,941 ) $ 855 Forfeited $ 18.33 (6,104 ) $ 9.56 (141,904 ) Unvested and outstanding at December 31, 2015 $ 18.62 10,619 $ 10.53 269,886 A summary of our Time and Performance award activity during the three years ended December 31, 2015 is presented in the following table: 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, 2013 $ 651.97 9,481 $ 298.15 55,824 Granted $ 626.02 2,839 $ 181.59 5,217 Vested $ 662.55 (2,509 ) $ 1,556 $ — — Forfeited $ 618.87 (1,734 ) $ 340.23 (3,171 ) Modified $ 626.00 11,169 $ 324.47 (11,169 ) Unvested and outstanding at December 31, 2013 $ 634.67 19,246 $ 307.45 46,701 Granted $ 818.50 5,245 $ 204.90 10,033 Vested $ 643.55 (4,951 ) $ 4,118 $ — — Forfeited $ 631.54 (3,045 ) $ 264.54 (8,452 ) Modified $ 969.00 9,339 $ 296.69 (9,339 ) Unvested and outstanding at December 31, 2014 $ 791.52 25,834 $ 292.92 38,943 Granted $ 533.80 610 $ 113.90 599 Vested $ 775.17 (8,468 ) $ 4,497 $ — — Forfeited $ 774.21 (3,997 ) $ 323.53 (11,094 ) Unvested and outstanding at December 31, 2015 $ 795.13 13,979 $ 278.97 28,448
Return on investment targets for Performance Vested shares	Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the remaining number of Performance Vested shares outstanding were reallocated among five targets for vesting. Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, as Time Vested awards; and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. As a result of these modifications, vesting requirements for all remaining Performance Vested awards are set at the following levels: Return on investment target Shares vested 175% per share 33 % of shares multiplied by the Vesting Fraction 200% per share 33 % of shares multiplied by the Vesting Fraction 250% per share 34 % of shares multiplied by the Vesting Fraction
Assumptions used in valuation of Performance Vested awards	The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows: 2015 2014 2013 Risk free interest rate 0.71 % to 1.44 % 0.25 % to 1.48 % 0.16 % to 2.46 % Expected volatility 71 % to 81 % 52 % to 56 % 38 % to 39 % Expected life 3 years 4 years 5 years Expected dividends $ — $ — $ —
Stock-based compensation cost	A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31: 2015 2014 2013 Stock-based compensation cost $ (2,169 ) $ 6,235 $ 7,819 Less: stock-based compensation cost capitalized 229 (2,346 ) (2,345 ) Stock-based compensation (credit) expense $ (1,940 ) $ 3,889 $ 5,474 Recognized tax (expense) benefit associated with stock-based compensation $ (229 ) $ 1,452 $ 2,031

Stockholders' equity (Tables)

Stockholders' equity (Tables)	12 Months Ended
	Dec. 31, 2015
Stockholders Equity Note [Abstract]
Summary of changes in common shares outstanding	The following is a summary of the changes in our common shares outstanding during the years ended December 31, 2015, 2014 and 2013: Common Stock Class A Class B Class C Class D Class E Class F Class G Total Shares issued at January 1, 2013 67,991 357,882 209,882 279,999 504,276 1 3 1,420,034 Restricted stock issuance 8,056 — — — — — — 8,056 Restricted stock repurchased (1,025 ) — — — — — — (1,025 ) Restricted stock forfeited (4,905 ) — — — — — — (4,905 ) Shares issued at December 31, 2013 70,117 357,882 209,882 279,999 504,276 1 3 1,422,160 Stock transfers (1) 293,023 (13,023 ) — (279,999 ) — — (1 ) — Restricted stock issuance 15,278 — — — — — — 15,278 Restricted stock repurchased (2,025 ) — — — — — — (2,025 ) Restricted stock forfeited (11,497 ) — — — — — — (11,497 ) Shares issued at December 31, 2014 364,896 344,859 209,882 — 504,276 1 2 1,423,916 Restricted stock issuance 1,209 — — — — — — 1,209 Restricted stock repurchased (5,725 ) — — — — — — (5,725 ) Restricted stock forfeited (15,091 ) — — — — — — (15,091 ) Shares issued at December 31, 2015 345,289 344,859 209,882 — 504,276 1 2 1,404,309 (1) In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

Commitments and contingencies (

Commitments and contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Unrecorded Unconditional Purchase Obligations Disclosure	Based on current prices, our estimated minimum purchase obligations under our CO 2 2016 $ 2,193 2017 1,290 2018 1,289 2019 1,290 2020 1,289 2021 and thereafter 3,066 $ 10,417
Schedule of Future Minimum Rental Payments for Operating Leases	As of December 31, 2015, total remaining payments associated with our operating leases were: 2016 $ 1,095 2017 1,095 2018 1,093 2019 1,088 2020 1,055 2021 and thereafter 1,018 $ 6,444

Oil and natural gas activities

Oil and natural gas activities (Tables)	12 Months Ended
	Dec. 31, 2015
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Abstract]
Cost incurred in oil and natural gas producing activities	Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31: 2015 2014 2013 Property acquisition costs Proved properties $ 1,192 $ 3,496 $ 69,962 Unproved properties 24,735 84,938 145,853 Total acquisition costs 25,927 88,434 215,815 Development costs 150,261 561,578 376,394 Exploration costs (1) 33,091 90,146 77,507 Total $ 209,279 $ 740,158 $ 669,716 (1) Includes $515, $152, and $37,344 of EOR costs in 2015, 2014, and 2013, respectively.
Depreciation, Depletion and Amortization Expense of Oil and Natural Gas Properties	Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows for the years ended December 31: 2015 2014 2013 DD&A $ 204,692 $ 231,761 $ 179,734 DD&A per BOE: $ 20.07 $ 21.10 $ 18.45

Disclosures about oil and nat38

Disclosures about oil and natural gas activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Summary of changes in quantities of proved oil and natural gas reserves	Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2015 are as follows: Oil (MBbls) Natural gas (MMcf) Natural gas liquids (MBbls) Total (MBoe) Proved developed and undeveloped reserves As of January 1, 2013 92,047 257,115 11,195 146,095 Purchase of minerals in place 3,283 3,618 1,059 4,945 Sales of minerals in place (5,174 ) (9,708 ) (324 ) (7,116 ) Extensions and discoveries 11,556 62,412 3,127 25,085 Revisions (1) (7,772 ) 9,735 1,479 (4,671 ) Improved recoveries 3,879 — — 3,879 Production (5,006 ) (20,250 ) (1,361 ) (9,742 ) Balance at December 31, 2013 92,813 302,922 15,175 158,475 Purchase of minerals in place 276 859 55 474 Sales of minerals in place (8,539 ) (79,579 ) (1,959 ) (23,761 ) Extensions and discoveries 12,776 56,159 3,405 25,541 Revisions (1) (3,356 ) (11,957 ) 1,741 (3,608 ) Improved recoveries 13,254 — — 13,254 Production (5,977 ) (20,648 ) (1,564 ) (10,982 ) Balance at December 31, 2014 101,247 247,756 16,853 159,393 Purchase of minerals in place 38 1,120 46 271 Sales of minerals in place (2,225 ) (3,656 ) (117 ) (2,951 ) Extensions and discoveries 3,651 13,759 1,096 7,040 Revisions (1) (19,840 ) (61,973 ) (4,257 ) (34,426 ) Improved recoveries (2) 36,414 — — 36,414 Production (5,519 ) (18,788 ) (1,550 ) (10,200 ) Balance at December 31, 2015 113,766 178,218 12,071 155,541 Proved developed reserves: January 1, 2013 54,737 185,826 9,218 94,926 December 31, 2013 56,360 196,920 11,484 100,664 December 31, 2014 54,862 158,265 11,787 93,027 December 31, 2015 40,300 132,323 9,169 71,524 Proved undeveloped reserves: January 1, 2013 37,310 71,289 1,977 51,169 December 31, 2013 36,453 106,002 3,691 57,811 December 31, 2014 46,385 89,491 5,066 66,366 December 31, 2015 73,466 45,895 2,902 84,017 (1) The downward revision in our reserves during 2015 was primarily due to the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. The downward revision in our reserves during 2014 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and a decline in the estimated sales margin on natural gas. The downward revision in our reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame and to negative technical revisions. The 2013 downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas. (2) Improved recoveries in 2015 resulted from the addition of reserves from remaining future phases of CO 2
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the year ended December 31, 2015 2014 2013 Future cash flows $ 6,327,363 $ 11,275,090 $ 10,660,532 Future production costs (2,670,692 ) (3,605,107 ) (3,841,723 ) Future development and abandonment costs (1,536,063 ) (1,726,955 ) (1,506,585 ) Future income tax provisions (89,999 ) (1,487,121 ) (1,328,925 ) Net future cash flows 2,030,609 4,455,907 3,983,299 Less effect of 10% discount factor (1,345,920 ) (2,561,207 ) (2,239,527 ) Standardized measure of discounted future net cash flows $ 684,689 $ 1,894,700 $ 1,743,772
Changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows: For the year ended December 31, 2015 2014 2013 Beginning of year $ 1,894,700 $ 1,743,772 $ 1,523,681 Sale of oil and natural gas produced, net of production costs (196,319 ) (502,928 ) (418,224 ) Net changes in prices and production costs (1) (2,230,601 ) 116,977 172,975 Extensions and discoveries 101,384 286,500 514,743 Improved recoveries 524,436 148,673 79,589 Changes in future development costs 204,199 (91,027 ) (236,121 ) Development costs incurred during the period that reduced future development costs 80,103 316,490 110,354 Revisions of previous quantity estimates (1) (495,794 ) (40,481 ) (95,855 ) Purchases and sales of reserves in place, net (47,079 ) (278,825 ) (20,021 ) Accretion of discount 237,134 223,324 152,830 Net change in income taxes (1) 605,766 (46,584 ) (60,981 ) Changes in production rates and other 6,760 18,809 20,802 End of year $ 684,689 $ 1,894,700 $ 1,743,772 (1) Amounts in 2015 are primarily the result of the decrease in SEC pricing, which resulted in a loss of reserves as extraction has become uneconomic, lower margins on existing reserves and a decrease in taxes as a result of the lower margins.
Prices used in determining future net revenues related to standardized measure calculation	The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation. 2015 2014 2013 Oil (per Bbl) $ 50.28 $ 94.99 $ 96.78 Natural gas (per Mcf) $ 2.58 $ 4.35 $ 3.67 Natural gas liquids (per Bbl) $ 15.84 $ 36.10 $ 32.53

Nature of operations and summ39

Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash and accounts receivable
Period within which joint interest accounts receivable are due	30 days
Period within which joint interest accounts receivable are past due	60 days
Components of accounts receivable
Joint interests	$ 14,149	$ 30,648
Accrued commodity sales	21,645	45,667
Derivative settlements	40,380	19,678
Other	3,329	2,738
Allowance for doubtful accounts	(503)	(287)
Accounts receivable, net	79,000	$ 98,444
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held at JP Morgan Chase Bank, N. A.	$ 13,507

Nature of operations and summ40

Nature of operations and summary of significant accounting policies (Inventories) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Inventory Adjustments [Abstract]
Equipment inventory	$ 11,470	$ 24,169
Commodities	1,698	2,575
Inventory valuation allowance	(839)	(1,187)
Inventories, net	12,329	$ 25,557
Loss on Impairment of Other Assets
Inventory [Line Items]
Inventory write-down	$ 10,192

Nature of operations and summ41

Nature of operations and summary of significant accounting policies--Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2015
Furniture and Fixtures
Property Plant And Equipment [Line Items]
Property and equipment, useful life	10 years
Automobiles and Trucks
Property Plant And Equipment [Line Items]
Property and equipment, useful life	5 years
Machinery and Equipment | Minimum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	10 years
Machinery and Equipment | Maximum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	20 years
Office and Computer Equipment | Minimum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	5 years
Office and Computer Equipment | Maximum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	10 years
Building and Improvements | Minimum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	10 years
Building and Improvements | Maximum
Property Plant And Equipment [Line Items]
Property and equipment, useful life	40 years

Nature of operations and summ42

Nature of operations and summary of significant accounting policies (Oil and Natural Gas Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized costs of unproved properties excluded from amortization
Capital costs for undeveloped acreage	$ 60,031	$ 190,356
Uncompleted Wells Equipment and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization	$ 6,874	26,023
CO2 Delivery Pipelines and Facilities
Capitalized costs of unproved properties excluded from amortization
Exploration and development costs excluded from amortization		$ 72,046

Nature of operations and summ43

Nature of operations and summary of significant accounting policies (Asset Impairment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Loss on impairment of oil and gas assets	$ 1,491,129	$ 0	$ 0
Loss on impairment of other assets	$ 6,015	$ 0	$ 3,490

Nature of operations and summ44

Nature of operations and summary of significant accounting policies (Income Taxes) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax penalties and interest accrued	$ 0	$ 0
Unrecognized tax benefits	$ 0	$ 0

Nature of operations and summ45

Nature of operations and summary of significant accounting policies (Gas Balancing) (Details) $ in Thousands	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)MMcf
Oil And Gas In Process Activities [Line Items]
Gas balancing payable | $	$ 1,303	$ 1,110
Under Production
Oil And Gas In Process Activities [Line Items]
Gas balancing volume (in MMcf)	0	2,005
Over Production
Oil And Gas In Process Activities [Line Items]
Gas balancing volume (in MMcf)	1,253	1,276

Nature of operations and summ46

Nature of operations and summary of significant accounting policies (Cost Reduction Intiatives) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 10,028	$ 0	$ 0
Severance and Termination Benefits
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives	$ 7,757

Going Concern and Liquidity--Na

Going Concern and Liquidity--Narrative (Details) $ in Thousands	Mar. 30, 2016USD ($)Installment	Feb. 11, 2016USD ($)	Mar. 31, 2016	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Mar. 01, 2016USD ($)	Dec. 31, 2012USD ($)
Going Concern And Liquidity [Line Items]
Total debt, net				$ 1,607,127	$ 1,633,802
Cash and cash equivalents				17,065	31,492	$ 48,595		$ 29,819
Net (loss) income				(1,333,844)	209,293	55,687
Current liabilities exceeded current assets				1,522,431
Deficit				$ 620,357	$ (711,858)	$ (497,264)		$ (462,857)
Credit Facility | Election One
Going Concern And Liquidity [Line Items]
Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination				30 days
Subsequent Event
Going Concern And Liquidity [Line Items]
Cash and cash equivalents	$ 176,000
Number of days to pay interest to avoid event of default			30 days
Subsequent Event | 8.25% Senior Notes due 2021
Going Concern And Liquidity [Line Items]
Interest payment deferred							$ 16,500
Subsequent Event | Credit Facility
Going Concern And Liquidity [Line Items]
Borrowed under credit facility		$ 141,000
Subsequent Event | Credit Facility | Election One
Going Concern And Liquidity [Line Items]
Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination	30 days
Number of installments to eliminate borrowings in excess of borrowing base as the result of a redetermination | Installment	6

Supplemental disclosures to t48

Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net cash provided by operating activities included:
Cash payments for interest	$ 116,379	$ 112,196	$ 107,122
Interest capitalized	(9,670)	(13,491)	(15,995)
Cash payments for interest, net of amounts capitalized	106,709	98,705	91,127
Cash payments for income taxes	640	591	641
Non-cash investing activities included:
Asset retirement obligation additions and revisions	4,000	7,461	9,036
Change in accrued oil and gas capital expenditures	$ (105,312)	$ 43,971	$ 27,875

Acquisitions and divestitures49

Acquisitions and divestitures (2015 Divestitures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of various non-core oil and gas properties		$ 109,710
SCOOP play
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of various non-core oil and gas properties	$ 36,654

Acquisitions and divestitures50

Acquisitions and divestitures (2014 Divestitures) (Details) $ in Thousands	1 Months Ended		12 Months Ended
	Jul. 31, 2014USD ($)	May. 31, 2014USD ($)	Dec. 31, 2014USD ($)Divestiture	Dec. 31, 2013USD ($)
Long Lived Assets Held For Sale [Line Items]
Number Of Divestitures | Divestiture			4
Number Of Planned Divestitures | Divestiture			5
Proceeds from sale of oil and gas properties				$ 109,710
Eagle Ford Formation, Texas
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties			$ 20,007
Andrews County, TX and Osage County, OK
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties			$ 24,478
Scout Energy Group I, LP | Fort Worth Basin
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties		$ 23,702
RKI Exploration And Production, LLC | Delaware Basin
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties		$ 124,717
RAM Energy, LLC | Ark-La-Tex
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties	$ 49,078
RAM Energy, LLC | Central Basin [Member]
Long Lived Assets Held For Sale [Line Items]
Proceeds from sale of oil and gas properties	$ 46,830

Acquisitions and divestitures51

Acquisitions and divestitures (2013 Acquisition and divestitures) (Details)	Dec. 18, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)a
Long Lived Assets Held For Sale [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 0	$ 0	$ 153,858,000
Business acquisition, date of acquisition				Dec. 18, 2013
Bargain purchase gain recognized				$ 0
Purchase Price Allocation
Payments to Acquire Businesses, Net of Cash Acquired		$ 0	$ 0	153,858,000
Proceeds from sale of oil and gas properties				109,710,000
Creek, Love, and Carter Counties, Oklahoma
Purchase Price Allocation
Proceeds from sale of oil and gas properties				61,440,000
Texas County, Oklahoma
Purchase Price Allocation
Proceeds from sale of oil and gas properties				$ 17,800,000
Cabot Oil & Gas Corporation
Long Lived Assets Held For Sale [Line Items]
Business acquisition, date of acquisition				Jan. 1, 2012
Cabot Oil & Gas Corporation | Panhandle Marmaton Play
Long Lived Assets Held For Sale [Line Items]
Oil and natural gas acres, gross | a				131,000
Oil and natural gas acres, net | a				66,000
Payments to Acquire Businesses, Net of Cash Acquired	$ 153,858,000
Acquisition related costs				$ 951,000
Purchase Price Allocation
Payments to Acquire Businesses, Net of Cash Acquired	153,858,000
Proved oil and natural gas properties	67,275,000
Unevaluated oil and natural gas properties	87,663,000
Asset retirement obligations	(1,080,000)
Fair value of net identifiable assets acquired	$ 153,858,000
Revenues				690,564,000
Operating expenses				448,751,000
Net income				$ 76,552,000

Property and Equipment--Compone

Property and Equipment--Components of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Furniture and fixtures	$ 2,518	$ 2,488
Automobiles and trucks	10,689	13,721
Machinery and equipment	55,963	57,922
Office and computer equipment	19,993	18,305
Building and improvements	25,534	29,322
Property and equipment, excluding land, gross	114,697	121,758
Less accumulated depreciation and amortization	75,041	64,310
Property and equipment, excluding land, net	39,656	57,448
Land	9,306	9,113
Property and equipment - at cost, net	$ 48,962	$ 66,561

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Long-term debt [Abstract]
Credit Facility		$ 367,000	$ 347,000
Real estate mortgage notes payable		10,182	10,705
Installment notes payable		1,799	4,252
Capital lease obligations		19,437	21,837
Total debt, net		1,607,127	1,633,802
Less current portion	[1]	1,607,127	5,377
Total long-term debt, net			1,628,425
9.875% Senior Notes due 2020
Long-term debt [Abstract]
Senior Notes		293,815	295,139
8.25% Senior Notes due 2021
Long-term debt [Abstract]
Senior Notes		384,045	400,000
7.625% Senior Notes due 2022
Long-term debt [Abstract]
Senior Notes		$ 530,849	$ 554,869
[1]	As a result of defaults on our debt as of the filing date of this report, our long-term debt was classified as current at December 31, 2015.

Debt (Components of Debt) (Pare

Debt (Components of Debt) (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
9.875% Senior Notes due 2020
Long-term debt [Abstract]
Unamortized discount	$ 4,185	$ 4,861
7.625% Senior Notes due 2022
Long-term debt [Abstract]
Unamortized premium	$ 4,939	$ 4,869
Senior Notes | 9.875% Senior Notes due 2020
Long-term debt [Abstract]
Stated interest rate	9.875%	9.875%
Senior Notes | 8.25% Senior Notes due 2021
Long-term debt [Abstract]
Stated interest rate	8.25%	8.25%
Senior Notes | 7.625% Senior Notes due 2022
Long-term debt [Abstract]
Stated interest rate	7.625%	7.625%
Mortgages | Minimum
Long-term debt [Abstract]
Stated interest rate	3.16%
Mortgages | Maximum
Long-term debt [Abstract]
Stated interest rate	5.46%
Secured Debt | Minimum
Long-term debt [Abstract]
Stated interest rate	2.85%
Secured Debt | Maximum
Long-term debt [Abstract]
Stated interest rate	5.95%

Debt (Maturities of Debt and Ca

Debt (Maturities of Debt and Capital Leases) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Maturities Of Long Term Debt [Abstract]
2,016	$ 4,409
2,017	370,600
2,018	3,302
2,019	12,328
2,020	298,687
2021 and thereafter	917,047
Long-term debt and capital leases, excluding premium or discount on Senior Notes	$ 1,606,373

Debt (Senior Notes) (Details)

Debt (Senior Notes) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsequent Event
Debt Instrument [Line Items]
Grace period to pay interest to avoid event of default	30 days
Senior Notes
Debt Instrument [Line Items]
Net amortization of discount (premium)		$ 945	$ (268)	$ (387)
Redemption price at change of control event, as a percentage of principal		101.00%
Senior Notes | Subsequent Event
Debt Instrument [Line Items]
Grace period to pay interest to avoid event of default	30 days
Senior Notes | 9.875% Senior Notes due 2020
Debt Instrument [Line Items]
Stated interest rate		9.875%	9.875%
Senior Notes | 8.25% Senior Notes due 2021
Debt Instrument [Line Items]
Stated interest rate		8.25%	8.25%
Senior Notes | 7.625% Senior Notes due 2022
Debt Instrument [Line Items]
Stated interest rate		7.625%	7.625%

Debt (Senior Secured Revolving

Debt (Senior Secured Revolving Credit Facility) (Details) - Credit Facility	12 Months Ended
	Dec. 31, 2015USD ($)qtr	Oct. 29, 2015USD ($)	Apr. 01, 2015USD ($)	Mar. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Borrowing base amount		$ 550,000,000	$ 550,000,000	$ 650,000,000
Commitment fee on unused portion of the borrowing base	0.50%
Number of consecutive quarters | qtr	4
Additional borrowing capacity	$ 300,000,000
Debt related fees	$ 1,404,000
Number of days to make election to eliminate borrowings in excess of borrowing base as the result of a redetermination	10 days
Election One
Line of Credit Facility [Line Items]
Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination	30 days
Equal monthly installment period to eliminate borrowings in excess of borrowing base as the result of redetermination	6 months
Election Two
Line of Credit Facility [Line Items]
Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination	30 days
Election Three
Line of Credit Facility [Line Items]
Number of days to eliminate borrowings in excess of borrowing base as the result of a redetermination	30 days
Minimum
Line of Credit Facility [Line Items]
Current Ratio covenant	100.00%
Interest coverage charge ratio	200.00%
Maximum
Line of Credit Facility [Line Items]
Ratio of consolidated secured net debt to consolidated EBITDAX covenant	225.00%
Eurodollar Rate Option
Line of Credit Facility [Line Items]
Additional interest rate on outstanding amounts in event of default	2.00%
One month interest period	1 month
Two month interest period	2 months
Three month interest period	3 months
Six month interest period	6 months
Eurodollar Rate Option | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Frequency of periodic interest payment on senior secured revolving credit facility	3 months
Eurodollar Rate Option | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.25%
Federal Funds Effective Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Adjusted LIBO Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%

Debt (Debt Issuance Costs and C

Debt (Debt Issuance Costs and Capital Leases) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Issuance Costs [Abstract]
Amortization of debt issuance costs	$ 1,921	$ 2,335	$ 2,197
Leases, Capital [Abstract]
Proceeds from sale and leaseback of assets	$ 0	0	24,500
U.S. Bank National Association | Capital Lease Obligations
Leases, Capital [Abstract]
Proceeds from sale and leaseback of assets			$ 24,500
Lease term	84 months
Purchase option period	72 months
Implicit interest rate	3.80%
Minimum lease payments	$ 3,181
Other Assets
Debt Issuance Costs [Abstract]
Unamortized debt issuance cost	$ 18,359	$ 20,937

Debt (Senior Note Repurchases)

Debt (Senior Note Repurchases) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Gain on extinguishment of debt		$ 31,590	$ 0	$ 0
Senior Notes
Debt Instrument [Line Items]
Senior note repurchase amount	$ 42,045	42,045
Debt instrument cash paid for repurchase	9,995
Gain on extinguishment of debt	31,590
Senior Notes | 9.875% Senior Notes due 2020
Debt Instrument [Line Items]
Senior note repurchase amount	2,000	2,000
Senior Notes | 8.25% Senior Notes due 2021
Debt Instrument [Line Items]
Senior note repurchase amount	15,955	15,955
Senior Notes | 7.625% Senior Notes due 2022
Debt Instrument [Line Items]
Senior note repurchase amount	$ 24,090	$ 24,090

Derivative instruments - Deriva

Derivative instruments - Derivatives Outstanding (Details) $ in Thousands		Mar. 26, 2015USD ($)bblMMBTU	Dec. 31, 2014USD ($)	Dec. 31, 2015USD ($)bblMMBTU$ / bbl$ / MMBTU	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Weighted average fixed price				72.42
Derivative Maturing in 2016 | NYMEX Strip Price
Derivative [Line Items]
Average forward price (USD per barrel)				41.45
Three-way collars
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $				$ (24)	$ 7,382	$ 14,548
Three-way collars | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl				240,000
Weighted average fixed price per Bbl, sold puts				84
Weighted average fixed price per Bbl, purchased puts				92
Weighted average fixed price per Bbl, sold calls				101.01
Collar with deferred premium | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]			480,000
Weighted average fixed price per Bbl, sold puts	[1]			40
Weighted average fixed price per Bbl, purchased puts	[1]			52.50
Weighted average fixed price per Bbl, sold calls	[1]			72.50
Weighted average fixed price per Bbl, Average premium	[1]			2.95
Collar with deferred premium | Derivative Maturing in 2017 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[1]			480,000
Weighted average fixed price per Bbl, sold puts	[1]			42.50
Weighted average fixed price per Bbl, purchased puts	[1]			55
Weighted average fixed price per Bbl, sold calls	[1]			80
Weighted average fixed price per Bbl, Average premium	[1]			2.78
Enhanced Swaps | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[2]			3,720,000
Weighted average fixed price	[2]			92.94
Weighted average fixed price per Bbl, sold puts	[2]			80.52
Floor price (USD per barrel)				60
Purchased Puts | Derivative Maturing in 2016 | Oil Derivative
Derivative [Line Items]
Volume | bbl	[2]			3,720,000
Weighted average fixed price per Bbl, purchased puts	[2]			60
Premium paid for put options on commodity derivative contracts | $			$ 20,609
Swaps
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $				$ 56,734	(6,607)	5,122
Swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU				14,000,000
Weighted average fixed price | $ / MMBTU				4.19
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU				12,700,000
Weighted average fixed price | $ / MMBTU				3.64
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU				8,250,000
Weighted average fixed price | $ / MMBTU				3.83
Natural gas basis protection swaps
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds | $				$ (283)	$ (579)	$ (557)
Natural gas basis protection swaps | Derivative Maturing in 2016 | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU				8,400,000
Weighted average fixed price | $ / MMBTU				0.36
Early settlement | Oil Derivative
Derivative [Line Items]
Volume | bbl		495,000
Early settlement | Natural Gas Derivative
Derivative [Line Items]
Volume | MMBTU		12,280,000
Settlement of non-hedge derivative instruments, net proceeds | $		$ 15,395
[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 $41.45 for 2016 as of December 31, 2015, the average realized price, and concurrently the floor price, of our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42 per barrel. In the event that prices increase above $60.00 per barrel upon settlement, 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		Dec. 31, 2015	Dec. 31, 2014
Fair value of derivative instruments
Derivative assets, gross		$ 164,396	$ 251,863
Derivative liabilities, gross		(1,158)	(309)
Derivative assets (liabilities), net		163,238	251,554
Netting adjustments	[1]	1,158	232
Derivative Liability, Netting adjustments	[1]	(1,158)	(232)
Current derivative assets, net		143,737	179,921
Current derivative liabilities, net		0	(77)
Current derivative assets (liabilities), net		143,737	179,844
Long-term derivative assets, net		$ 19,501	$ 71,710
Long-term derivative liabilities, net
Long-term derivative assets (liabilities), net		$ 19,501	$ 71,710
Natural Gas Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross		41,328	32,939
Derivative assets (liabilities), net		41,328	32,939
Natural Gas Derivative | Natural gas basis protection swaps
Fair value of derivative instruments
Derivative assets, gross			292
Derivative liabilities, gross		(1,158)	(309)
Derivative assets (liabilities), net		(1,158)	(17)
Oil Derivative | Swaps
Fair value of derivative instruments
Derivative assets, gross			23,465
Derivative assets (liabilities), net			23,465
Oil Derivative | Three-way collars
Fair value of derivative instruments
Derivative assets, gross		6,500	1,175
Derivative assets (liabilities), net		6,500	1,175
Oil Derivative | Enhanced Swaps
Fair value of derivative instruments
Derivative assets, gross		45,516	100,724
Derivative assets (liabilities), net		45,516	100,724
Oil Derivative | Purchased and sold puts
Fair value of derivative instruments
Derivative assets, gross		71,052	93,268
Derivative assets (liabilities), net		$ 71,052	$ 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	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative settlements receivable included in accounts receivable	$ 40,380	$ 19,678

Derivative instruments (Effec63

Derivative instruments (Effect of Derivative Instruments on the Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Non-Hedge Derivative Gains (Losses) [Line Items]
Non-hedge derivative gain (losses)	$ 145,288	$ 231,320	$ (21,635)
Swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(15,077)	59,627	(20,717)
(Payments on) receipts from settlement of non-hedge derivative instruments	56,734	(6,607)	5,122
Three-way collars
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	5,325	(1,597)	(23,459)
(Payments on) receipts from settlement of non-hedge derivative instruments	(24)	7,382	14,548
Enhanced Swaps and Put Options
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(77,424)	172,533	186
(Payments on) receipts from settlement of non-hedge derivative instruments	177,178	2,221	0
Natural gas basis protection swaps
Non-Hedge Derivative Gains (Losses) [Line Items]
Change in fair value of non-hedge derivatives	(1,141)	(1,660)	3,242
(Payments on) receipts from settlement of non-hedge derivative instruments	$ (283)	$ (579)	$ (557)

Fair value measurements (Recurr

Fair value measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross		$ 164,396	$ 251,863
Derivative liabilities, gross		(1,158)	(309)
Derivative assets (liabilities), net		163,238	251,554
Derivative assets, amount offset		(1,158)	(232)
Derivative liabilities, amounts offset		1,158	232
Derivative assets, net		163,238	251,631
Derivative liabilities, net		0	(77)
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net		163,238	251,554
Derivative assets, amount offset	[1]	(1,158)	(232)
Derivative liabilities, amounts offset	[1]	1,158	232
Derivative assets amount offset (liabilities), net	[1]	0	0
Derivative assets, net		163,238	251,631
Derivative liabilities, net		0	(77)
Recurring Fair Value Measurements | Significant Other Observable Inputs (Level 2)
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross		41,328	56,696
Derivative liabilities, gross		(1,158)	(309)
Derivative assets (liabilities), net		40,170	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		123,068	195,167
Derivative liabilities, gross		0	0
Derivative assets (liabilities), net		$ 123,068	$ 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	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Level 3 Rollforward
Beginning balance	$ 195,167	$ 3,622
Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)	105,055	180,539
Purchases	0	20,609
Settlements received	(177,154)	(9,603)
Ending balance	123,068	195,167
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period	$ 61,260	$ 169,442

Fair value measurements (Nonrec

Fair value measurements (Nonrecurring Fair Value Measurements) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Nonrecurring Fair Value Measurements
Loss on impairment of other assets	$ 6,015	$ 0	$ 3,490
Significant Unobservable Inputs (Level 3) | Nonrecurring Fair Value Measurements
Nonrecurring Fair Value Measurements
Annual inflation rate	2.91%	2.95%
Credit-adjusted risk-free interest rate	15.09%	7.60%
Loss on impairment of other assets	$ 6,015	$ 0	$ 3,490

Fair value measurements (Fair V

Fair value measurements (Fair Value of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value of Other Financial Instruments
Credit Facility	$ 367,000	$ 347,000
9.875% Senior Notes due 2020
Fair Value of Other Financial Instruments
Senior Notes	293,815	295,139
8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	384,045	400,000
7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	530,849	554,869
Significant Other Observable Inputs (Level 2) | Carrying Value
Fair Value of Other Financial Instruments
Credit Facility	367,000	347,000
Other secured debt	11,981	14,957
Long-term debt	1,587,690	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	293,815	295,139
Significant Other Observable Inputs (Level 2) | Carrying Value | 8.25% Senior Notes due 2021
Fair Value of Other Financial Instruments
Senior Notes	384,045	400,000
Significant Other Observable Inputs (Level 2) | Carrying Value | 7.625% Senior Notes due 2022
Fair Value of Other Financial Instruments
Senior Notes	530,849	554,869
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Fair Value of Other Financial Instruments
Credit Facility	367,000	347,000
Other secured debt	11,981	14,957
Long-term debt	672,165	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	75,750	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	96,956	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	$ 120,478	$ 379,775

Fair value measurements (Counte

Fair value measurements (Counterparty Credit Risk) (Details) $ in Thousands	Dec. 31, 2015USD ($)financial_institutions
Counterparty Credit Risk
Derivative liabilities subject to acceleration | $	$ (1,158)
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	7
Derivative contracts, number of counterparties subject to offset under credit facility	7

Fair value measurements (Deriva

Fair value measurements (Derivatives Offset in the Consolidated Balance Sheets) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative assets, gross		$ 164,396	$ 251,863
Derivative assets, amount offset		(1,158)	(232)
Derivative assets		163,238	251,631
Derivative assets, not offset	[1]	0	0
Credit facility balance available to offset net derivative assets		(103,618)	(118,430)
Derivative asset, net		59,620	133,201
Derivative liabilities, gross		(1,158)	(309)
Derivative liabilities, amounts offset		1,158	232
Derivative liabilities		0	(77)
Derivative liabilities, not offset	[1]	0	0
Credit facility balance available to offset net derivative liabilities		0	0
Derivative liability, net		0	(77)
Derivative Asset (Liability), Fair Value, Gross Asset		163,238	251,554
Derivative Asset (Liability), Fair Value, Gross Liability		0	0
Derivative Asset (Liability), Net		163,238	251,554
Derivative liability asset not offset	[1]	0	0
Derivative asset (liability), net		$ 59,620	$ 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.

Fair value measurements (Percen

Fair value measurements (Percentages of Total Commodity Sales Excluding Effects of Hedging Activities (Details) - Customer Concentration Risk - Commodity Sales	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Valero Energy Corporation
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	20.70%	23.70%	20.10%
Coffeyville Resources LLC
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	14.50%	14.00%	19.10%
Phillips 66 Company
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	11.80%

Asset retirement obligations (D

Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 47,424	$ 55,179
Liabilities incurred in current period	1,861	5,011
Liabilities settled or disposed in current period	(6,472)	(19,184)
Revisions in estimated cash flows	2,139	2,450
Accretion expense	3,660	3,968
Ending balance	48,612	47,424
Less current portion included in accounts payable and accrued liabilities	2,178	4,147
Asset retirement obligations, long-term	46,434	43,277
Cash in escrow	$ 1,567	$ 1,568

Income Taxes--Component of Inco

Income Taxes--Component of Income Tax (Benefit) Expense from Continuing Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current income taxes
Federal	$ (21)	$ (22)	$ (29)
State	195	574	1,144
Total current income taxes	174	552	1,115
Deferred income taxes
Federal	(161,879)	115,699	30,327
State	(15,514)	8,192	1,407
Total deferred income taxes	(177,393)	123,891	31,734
Income tax (benefit) expense	$ (177,219)	$ 124,443	$ 32,849

Income Taxes--Rate Reconciliati

Income Taxes--Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State income taxes, net of federal benefit	3.10%	2.60%	3.80%
Statutory depletion	(0.00%)	(0.20%)	(0.70%)
Valuation allowance	(26.50%)	0.00%	(1.70%)
Other, net	0.10%	(0.10%)	0.70%
Effective tax rate	11.70%	37.30%	37.10%

Income Taxes--Components of Def

Income Taxes--Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Asset retirement obligations	$ 14,669		$ 12,988
Accrued expenses, allowance and other	11,564		15,057
Property and equipment	259,096		0
Inventories	372		0
Net operating loss carryforwards - Federal	154,265		121,556
Net operating loss carryforwards - State	21,466		15,052
Statutory depletion carryforwards	3,962		3,833
Alternative minimum tax credit carryforwards	308		308
Deferred tax assets, gross	465,702		168,794
Less valuation allowance	(411,147)	$ (225,000)	(10,499)
Deferred tax asset	54,555		158,295
Derivative instruments	(54,555)		(88,910)
Property and equipment	0		(245,629)
Inventories	0		(1,243)
Deferred tax liability	(54,555)		(335,782)
Net deferred tax liability	0		(177,487)
Less net current deferred tax liability	(53,914)		(60,728)
Long-term deferred tax liability	0		(116,759)
Long-term deferred tax asset	$ 53,914		$ 0

Income Taxes--Narrative (Detail

Income Taxes--Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Income Tax Disclosure [Line Items]
Estimated valuation allowance	$ 411,147	$ 225,000	$ 10,499
Discrete item associated with Federal and State NOL carryforwards		$ 126,000
Valuation allowance, Deferred tax asset, Increase (Decrease)	176,000
Deferred tax assets, Net	$ 0
Purchase or sale of stock percentage	5.00%
Offering stock period	3 years
Future equity transactions percentage	5.00%
Minimum
Income Tax Disclosure [Line Items]
Changes in beneficial ownership percentage	50.00%
State and Local Jurisdiction
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 530,000
Internal Revenue Service (IRS)
Income Tax Disclosure [Line Items]
Operating loss carryforwards	441,000
Operating loss carryforwards, not subject to expiration	$ 11,000

Stock-based compensation (Phant

Stock-based compensation (Phantom Stock Plan and Restricted Stock Unit Plan) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Phantom Stock Plan | Phantom Shares
Stock-Based Compensation [Line Items]
Maximum percentage of fair market value of the company available for share-based awards	2.00%
Maximum individual award as a percentage of shares available for award	5.00%
Award vesting period (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	$ 17.01	$ 16.87
Granted ($ per share)	0	0	0
Vested ($ per share)	24.48	12.61	16.20
Forfeited ($ per share)	18.33	19.95	17.57
Unvested and outstanding at end of period ($ per share)	$ 18.62	$ 20.18	$ 17.01
Shares
Unvested and outstanding at beginning of period (in shares)	23,179	53,162	84,764
Granted (in shares)	0	0	0
Vested (in shares)	(6,456)	(22,041)	(21,260)
Forfeited (in shares)	(6,104)	(7,942)	(10,342)
Unvested and outstanding at end of period (in shares)	10,619	23,179	53,162
Vest date fair value
Vest date fair value	$ 25	$ 212	$ 273
Non-Officer Restricted Stock Unit Plan | Restricted Stock Units (RSU)
Stock-Based Compensation [Line Items]
Maximum percentage of fair market value of the company available for share-based awards	2.00%
Days from vesting date to cash settlement	120 days
Weighted average grant date fair value
Unvested and outstanding at beginning of period ($ per share)	$ 9.91	$ 13.53	$ 17.12
Granted ($ per share)	14.88	8.52	12.45
Vested ($ per share)	10.73	13.96	17.12
Forfeited ($ per share)	9.56	9.85	14.27
Unvested and outstanding at end of period ($ per share)	$ 10.53	$ 9.91	$ 13.53
Shares
Unvested and outstanding at beginning of period (in shares)	569,160	325,297	151,909
Granted (in shares)	59,571	504,752	291,253
Vested (in shares)	(216,941)	(118,400)	(50,246)
Forfeited (in shares)	(141,904)	(142,489)	(67,619)
Unvested and outstanding at end of period (in shares)	269,886	569,160	325,297
Vest date fair value
Vest date fair value	$ 855	$ 1,094	$ 626
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	8 months 12 days

Stock-based compensation (Cash

Stock-based compensation (Cash Incentive Plan) (Details) - The 2015 Cash LTIP $ in Thousands	12 Months Ended
	Dec. 31, 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
Compensation expense recorded	$ 610

Stock-based compensation (2010

Stock-based compensation (2010 Equity Incentive Plan) (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 01, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Vest date fair value
Restricted stock		5,725	2,025	1,025
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding		$ 261
Common Class A
Vest date fair value
Restricted stock		5,725	2,025	1,025
Restricted Stock | 2010 Equity Incentive Plan | Performance Vested, modified
Stock-Based Compensation [Line Items]
Percentage of Performance Vested awards outstanding modified		20.00%
Incremental compensation cost			$ 8,536	$ 4,322
Restricted Stock | 2010 Equity Incentive Plan | Performance Vested, modified | Return on Investment Target Five
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage	350.00%	400.00%
Restricted Stock | 2010 Equity Incentive Plan | Performance Vested | Return on Investment Target One
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage		175.00%
Vesting Percentage		33.00%
Restricted Stock | 2010 Equity Incentive Plan | Performance Vested | Return on Investment Target Two
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage		200.00%
Vesting Percentage		33.00%
Restricted Stock | 2010 Equity Incentive Plan | Performance Vested | Return on Investment Target Three
Stock-Based Compensation [Line Items]
Return On Investment Target Percentage		250.00%
Vesting Percentage		34.00%
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	$ 634.67	$ 651.97
Granted ($ per share)		533.80	818.50	626.02
Vested ($ per share)		775.17	643.55	662.55
Forfeited ($ per share)		774.21	631.54	618.87
Modified ($ per share)			969	626
Unvested and outstanding at end of period ($ per share)		$ 795.13	$ 791.52	$ 634.67
Shares
Unvested and outstanding at beginning of period (in shares)		25,834	19,246	9,481
Granted (in shares)		610	5,245	2,839
Vested (in shares)		(8,468)	(4,951)	(2,509)
Forfeited (in shares)		(3,997)	(3,045)	(1,734)
Modified (in shares)			9,339	11,169
Unvested and outstanding at end of period (in shares)		13,979	25,834	19,246
Vest date fair value
Vest date fair value		$ 4,497	$ 4,118	$ 1,556
Restricted stock		5,725	2,025	1,025
Shares expected to be repurchased during the next twelve months		2,355
Estimated fair value per share at end of period ($ per share)		$ 18.70
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	$ 307.45	$ 298.15
Granted ($ per share)		113.90	204.90	181.59
Vested ($ per share)		0	0	0
Forfeited ($ per share)		323.53	264.54	340.23
Modified ($ per share)			296.69	324.47
Unvested and outstanding at end of period ($ per share)		$ 278.97	$ 292.92	$ 307.45
Shares
Unvested and outstanding at beginning of period (in shares)		38,943	46,701	55,824
Granted (in shares)		599	10,033	5,217
Vested (in shares)		0	0	0
Forfeited (in shares)		(11,094)	(8,452)	(3,171)
Modified (in shares)			(9,339)	(11,169)
Unvested and outstanding at end of period (in shares)		28,448	38,943	46,701

Stock-Based Compensation--Varia

Stock-Based Compensation--Variables and Assumptions Used to Value Restricted Stock Awards (Details) - 2010 Equity Incentive Plan - Restricted Stock - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Time Vested | Common Class A
Stock-Based Compensation [Line Items]
Discount for lack of marketability	25.00%	20.00%	17.00%
Performance Vested
Stock-Based Compensation [Line Items]
Risk free interest rate, minimum	0.71%	0.25%	0.16%
Risk free interest rate, maximum	1.44%	1.48%	2.46%
Expected volatility, minimum	71.00%	52.00%	38.00%
Expected volatility, maximum	81.00%	56.00%	39.00%
Expected life	3 years	4 years	5 years
Expected dividends	$ 0	$ 0	$ 0

Stock-based compensation (Stock

Stock-based compensation (Stock-based compensation cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost	$ (2,169)	$ 6,235	$ 7,819
Less: stock-based compensation cost capitalized	229	(2,346)	(2,345)
Stock-based compensation (credit) expense	(1,940)	3,889	5,474
Recognized tax (expense) benefit associated with stock-based compensation	(229)	1,452	2,031
Payments for stock-based compensation	3,991	2,995	$ 1,533
Stock-based compensation costs included in accrued payroll and benefits payable	81	$ 4,830
Unrecognized compensation cost	$ 4,281
Years over which unrecognized compensation cost is expected to be recognized	1 year 8 months 12 days

Stockholders' equity (Details)

Stockholders' equity (Details)		Jan. 13, 2014shares	Dec. 31, 2014$ / sharesshares	Dec. 31, 2015USD ($)Director$ / shares	Jan. 12, 2014	Apr. 12, 2010classes_of_stockStockholder$ / sharesshares
Equity [Line Items]
Number of classes of common stock | classes_of_stock						7
Common stock, par value | $ / shares						$ 0.01
Minimum proceeds from Qualified IPO required to trigger share conversion | $				$ 250,000,000
Minimum percentage of beneficial ownership required to retain rights and preferences under stockholders agreement				5.00%	5.00%
Healthcare of Ontario Pension Plan Trust Fund
Equity [Line Items]
Maximum percentage of common stock that may be acquired					25.00%
CCMP
Equity [Line Items]
Maximum percentage of common stock that may be sold					20.00%
Multiple of price per share paid by CCMP that must be received by the Company for Demand IPO					1.75
Fischer Investments, L.L.C.
Equity [Line Items]
Maximum percentage of common stock that may be sold					20.00%
Common Class G
Equity [Line Items]
Common stock, par value | $ / shares			$ 0.01	$ 0.01
Common stock issued to existing stockholders						1
Number of common stockholders | Stockholder						2
Stock transfers	[1]		(1)
Common Class G | CHK Energy Holdings Inc.
Equity [Line Items]
Stock transfers			1
Common Class A
Equity [Line Items]
Common stock, par value | $ / shares			$ 0.01	0.01
Stock transfers	[1]		293,023
Common Class A | Chesapeake | Converted from Common Class D and Common Class G To Common Class A
Equity [Line Items]
Company Shares, Transactions Between Company Stockholders, Shares		280,000
Common Class A | Healthcare of Ontario Pension Plan Trust Fund
Equity [Line Items]
Company Shares, Transactions Between Company Stockholders, Shares		15,078
Common Class A | Healthcare of Ontario Pension Plan Trust Fund | Converted from Common Class B To Common Class A
Equity [Line Items]
Company Shares, Transactions Between Company Stockholders, Shares		13,023
Class C Common Stock
Equity [Line Items]
Common stock, par value | $ / shares			$ 0.01	0.01
Class E Common Stock
Equity [Line Items]
Common stock, par value | $ / shares			0.01	$ 0.01
Number of directors | Director				2
Class F Common Stock
Equity [Line Items]
Common stock, par value | $ / shares			$ 0.01	$ 0.01
Class D Common Stock
Equity [Line Items]
Stock transfers	[1]		(279,999)
Class D Common Stock | CHK Energy Holdings Inc.
Equity [Line Items]
Stock transfers			279,999
Common Class B
Equity [Line Items]
Common stock, par value | $ / shares			$ 0.01	$ 0.01
Stock transfers	[1]		(13,023)
Minimum percentage ownership of common stock owned as of the Closing Date						80.00%
Class B and C Common Stock
Equity [Line Items]
Number of directors | Director				3
[1]	In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

Stockholders' equity - Summary

Stockholders' equity - Summary of Changes in Common Shares Outstanding (Details) - shares		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity [Line Items]
Balance at beginning of period (in shares)		1,423,916	1,422,160	1,420,034
Restricted stock issuance		1,209	15,278	8,056
Restricted stock repurchased		(5,725)	(2,025)	(1,025)
Restricted stock forfeited		(15,091)	(11,497)	(4,905)
Balance at end of period (in shares)		1,404,309	1,423,916	1,422,160
Common Class A
Equity [Line Items]
Balance at beginning of period (in shares)		364,896	70,117	67,991
Stock transfers	[1]		293,023
Restricted stock issuance		1,209	15,278	8,056
Restricted stock repurchased		(5,725)	(2,025)	(1,025)
Restricted stock forfeited		(15,091)	(11,497)	(4,905)
Balance at end of period (in shares)		345,289	364,896	70,117
Class B Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		344,859	357,882	357,882
Stock transfers	[1]		(13,023)
Balance at end of period (in shares)		344,859	344,859	357,882
Class C Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		209,882	209,882	209,882
Balance at end of period (in shares)		209,882	209,882	209,882
Class D Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)			279,999	279,999
Stock transfers	[1]		(279,999)
Balance at end of period (in shares)				279,999
Class E Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		504,276	504,276	504,276
Balance at end of period (in shares)		504,276	504,276	504,276
Class F Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		1	1	1
Balance at end of period (in shares)		1	1	1
Class G Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		2	3	3
Stock transfers	[1]		(1)
Balance at end of period (in shares)		2	2	3
[1]	In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

Retirement Benefits - Additiona

Retirement Benefits - Additional information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Person	Dec. 31, 2014USD ($)Person	Dec. 31, 2013USD ($)Person
Compensation And Retirement Disclosure [Abstract]
Matched employee contribution	100.00%	100.00%	100.00%
Employee contribution on gross wages	7.00%	7.00%	7.00%
Number of employee participating in plan | Person	395	625	585
Contribution expense | $	$ 2,363	$ 3,592	$ 3,621

Commitments and Contingencies -

Commitments and Contingencies - Additional information (Details) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Jun. 30, 2014Lease	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)contractsupplierMMcf	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Loss Contingencies [Line Items]
Letters of credit outstanding		$ 828	$ 828	$ 920
Interest paid			116,379	112,196	$ 107,122
Leases, Operating [Abstract]
Rent expense			$ 8,753	11,088	8,967
Maximum remaining term of operating leases			5 years
Other commitments		4,101	$ 4,101
Severance Payable If Terminated Under Change In Control
Other Contingencies [Abstract]
Maximum amount payable under agreement for terminated officers		14,532	$ 14,532
CO2 Compressor [Member]
Leases, Operating [Abstract]
Number Of Operating Leases | Lease	2
Operating lease expire, year	2,021
Minimum | Pending Litigation
Loss Contingency, Information about Litigation Matters [Abstract]
Damages sought		$ 5,000
C O 2 Purchase Contract
Loss Contingencies [Line Items]
Number of short-term interim agreements | contract			4
Number of suppliers | supplier			4
Number of short-term interim agreements | contract			1
Number of short-term interim agreements | contract			2
Minimum volume required (MMcf/d) | MMcf			35
Potential purchase volume rate reduction			100.00%
Contract term			10 years
Notice required for purchase volume rate reduction			6 months
Average volume purchased (MMcf/d) | MMcf			49
Purchases under CO2 contracts			$ 3,000	4,890	3,849
C O 2 Purchase Contract | Minimum
Loss Contingencies [Line Items]
Average volume purchased (MMcf/d) | MMcf			38
Letter of Credit
Loss Contingencies [Line Items]
Interest paid			$ 0	0	0
Proceeds from Letters			$ 0	$ 0	$ 0

Commitments and Contingencies85

Commitments and Contingencies - Minimum Purchase Obligations (Details) - C O 2 Purchase Contract $ in Thousands	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
2,016	$ 2,193
2,017	1,290
2,018	1,289
2,019	1,290
2,020	1,289
2021 and thereafter	3,066
Total estimated minimum purchase obligations under CO2 contracts	$ 10,417

Commitments and Contingencies86

Commitments and Contingencies - Operating Lease Schedule (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 1,095
2,017	1,095
2,018	1,093
2,019	1,088
2,020	1,055
2021 and thereafter	1,018
Total	$ 6,444

Oil and Natural Gas Activities-

Oil and Natural Gas Activities--Costs Incurred (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property acquisition costs
Proved properties		$ 1,192	$ 3,496	$ 69,962
Unproved properties		24,735	84,938	145,853
Total acquisition costs		25,927	88,434	215,815
Development costs		150,261	561,578	376,394
Exploration costs	[1]	33,091	90,146	77,507
Total		$ 209,279	$ 740,158	$ 669,716
[1]	Includes $515, $152, and $37,344 of EOR costs in 2015, 2014, and 2013, respectively.

Oil and Natural Gas Activitie88

Oil and Natural Gas Activities--Costs Incurred (Parenthetical) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	[1]	$ 33,091	$ 90,146	$ 77,507
Enhanced Oil Recovery
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs		$ 515	$ 152	$ 37,344
[1]	Includes $515, $152, and $37,344 of EOR costs in 2015, 2014, and 2013, respectively.

Oil and Natural Gas Activitie89

Oil and Natural Gas Activities--Depreciation, Depletion and Amortization Expense of Oil and Natural Gas Properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe	Dec. 31, 2013USD ($)$ / Boe
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Abstract]
DD&A | $	$ 204,692	$ 231,761	$ 179,734
DD&A per BOE: | $ / Boe	20.07	21.10	18.45

Oil and Natural Gas Activitie90

Oil and Natural Gas Activities--Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property costs excluded from amortization	$ 66,905	$ 288,425
Incurred During Current Reporting Period
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property costs excluded from amortization	24,587
Incurred One Year Prior To Current Reporting Period
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property costs excluded from amortization	37,846
Incurred Two Years Prior To Current Reporting Period
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproved property costs excluded from amortization	$ 4,472
Minimum
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Evaluation period of oil and natural gas properties (in years)	2 years
Maximum
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Evaluation period of oil and natural gas properties (in years)	5 years

Disclosures about Oil and Nat91

Disclosures about Oil and Natural Gas Activities (Unaudited)--Summary of Changes in Quantities of Proved Reserves (Details)		12 Months Ended
		Dec. 31, 2015MBoeMMcfMMBbls		Dec. 31, 2014MBoeMMcfMMBbls	Dec. 31, 2013MBoeMMcfMMBbls	Jan. 01, 2013MBoeMMcfMMBbls
Reserve Quantities [Line Items]
Balance at beginning of period | MBoe		159,393		158,475	146,095
Purchase of minerals in place | MBoe		271		474	4,945
Sales of minerals in place | MBoe		(2,951)		(23,761)	(7,116)
Extensions and discoveries | MBoe		7,040		25,541	25,085
Revisions | MBoe	[1]	(34,426)		(3,608)	(4,671)
Improved recoveries | MBoe		36,414	[2]	13,254	3,879
Production | MBoe		(10,200)		(10,982)	(9,742)
Balance at end of period | MBoe		155,541		159,393	158,475
Proved developed reserves | MBoe		71,524		93,027	100,664	94,926
Proved undeveloped reserves | MBoe		84,017		66,366	57,811	51,169
Oil [Member]
Reserve Quantities [Line Items]
Balance at beginning of period		101,247		92,813	92,047
Purchase of minerals in place		38		276	3,283
Sales of minerals in place		(2,225)		(8,539)	(5,174)
Extensions and discoveries		3,651		12,776	11,556
Revisions	[1]	(19,840)		(3,356)	(7,772)
Improved recoveries		36,414	[2]	13,254	3,879
Production		(5,519)		(5,977)	(5,006)
Balance at end of period		113,766		101,247	92,813
Proved developed reserves		40,300		54,862	56,360	54,737
Proved undeveloped reserves		73,466		46,385	36,453	37,310
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance at beginning of period | MMcf		247,756		302,922	257,115
Purchase of minerals in place | MMcf		1,120		859	3,618
Sales of minerals in place | MMcf		(3,656)		(79,579)	(9,708)
Extensions and discoveries | MMcf		13,759		56,159	62,412
Revisions | MMcf	[1]	(61,973)		(11,957)	9,735
Improved recoveries | MMcf		0	[2]	0	0
Production | MMcf		(18,788)		(20,648)	(20,250)
Balance at end of period | MMcf		178,218		247,756	302,922
Proved developed reserves | MMcf		132,323		158,265	196,920	185,826
Proved undeveloped reserves | MMcf		45,895		89,491	106,002	71,289
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance at beginning of period		16,853		15,175	11,195
Purchase of minerals in place		46		55	1,059
Sales of minerals in place		(117)		(1,959)	(324)
Extensions and discoveries		1,096		3,405	3,127
Revisions	[1]	(4,257)		1,741	1,479
Improved recoveries		0	[2]	0	0
Production		(1,550)		(1,564)	(1,361)
Balance at end of period		12,071		16,853	15,175
Proved developed reserves		9,169		11,787	11,484	9,218
Proved undeveloped reserves		2,902		5,066	3,691	1,977
[1]	The downward revision in our reserves during 2015 was primarily due to the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. The downward revision in our reserves during 2014 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and a decline in the estimated sales margin on natural gas. The downward revision in our reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame and to negative technical revisions. The 2013 downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.
[2]	Improved recoveries in 2015 resulted from the addition of reserves from remaining future phases of CO2 injection at our North Burbank EOR unit.

Disclosures about Oil and Nat92

Disclosures about Oil and Natural Gas Activities (Unaudited)--Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Standardized Measure [Abstract]
Future cash flows	$ 6,327,363	$ 11,275,090	$ 10,660,532
Future production costs	(2,670,692)	(3,605,107)	(3,841,723)
Future development and abandonment costs	(1,536,063)	(1,726,955)	(1,506,585)
Future income tax provisions	(89,999)	(1,487,121)	(1,328,925)
Net future cash flows	2,030,609	4,455,907	3,983,299
Less effect of 10% discount factor	(1,345,920)	(2,561,207)	(2,239,527)
Standardized measure of discounted future net cash flows	$ 684,689	$ 1,894,700	$ 1,743,772	$ 1,523,681

Disclosures about Oil and Nat93

Disclosures about Oil and Natural Gas Activities (Unaudited)--Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Principal Sources Of Change In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves [Abstract]
Beginning of year		$ 1,894,700	$ 1,743,772	$ 1,523,681
Sale of oil and natural gas produced, net of production costs		(196,319)	(502,928)	(418,224)
Net changes in prices and production costs	[1]	(2,230,601)	116,977	172,975
Extensions and discoveries		101,384	286,500	514,743
Improved recoveries		524,436	148,673	79,589
Changes in future development costs		204,199	(91,027)	(236,121)
Development costs incurred during the period that reduced future development costs		80,103	316,490	110,354
Revisions of previous quantity estimates	[1]	(495,794)	(40,481)	(95,855)
Purchases and sales of reserves in place, net		(47,079)	(278,825)	(20,021)
Accretion of discount		237,134	223,324	152,830
Net change in income taxes	[1]	605,766	(46,584)	(60,981)
Changes in production rates and other		6,760	18,809	20,802
End of year		$ 684,689	$ 1,894,700	$ 1,743,772
[1]	Amounts in 2015 are primarily the result of the decrease in SEC pricing, which resulted in a loss of reserves as extraction has become uneconomic, lower margins on existing reserves and a decrease in taxes as a result of the lower margins.

Disclosures about Oil and Nat94

Disclosures about Oil and Natural Gas Activities (Unaudited)--Prices Used in Determining Future Net Revenues (Details)	12 Months Ended
	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / bbl$ / Mcf	Dec. 31, 2013$ / bbl$ / Mcf
Oil [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price before field differentials used in determining future net revenues	50.28	94.99	96.78
Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price before field differentials used in determining future net revenues | $ / Mcf	2.58	4.35	3.67
Natural Gas Liquids [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Price before field differentials used in determining future net revenues	15.84	36.10	32.53