Chaparral Energy (CHAP) 10-K 31 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 31, 2017	Jun. 30, 2016
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, 2016
Document Fiscal Year Focus	2,016
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		37,048,110
Common Class B
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		7,856,404

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 186,480	$ 17,065
Accounts receivable, net	46,226	79,000
Inventories, net	7,351	12,329
Prepaid expenses	3,886	3,700
Derivative instruments	0	143,737
Total current assets	243,943	255,831
Property and equipment—at cost, net	41,347	48,962
Oil and natural gas properties, using the full cost method:
Proved	4,323,964	4,128,193
Unevaluated (excluded from the amortization base)	20,353	66,905
Accumulated depreciation, depletion, amortization and impairment	(3,789,133)	(3,396,261)
Total oil and natural gas properties	555,184	798,837
Derivative instruments	0	19,501
Deferred income taxes	0	53,914
Other assets	5,513	4,268
Total assets	845,987	1,181,313
Current liabilities:
Accounts payable and accrued liabilities	42,442	66,222
Accrued payroll and benefits payable	3,459	15,305
Accrued interest payable	732	23,303
Revenue distribution payable	9,426	12,391
Long-term debt and capital leases, classified as current	469,112	1,583,701
Derivative instruments	7,525	0
Deferred income taxes		53,914
Total current liabilities	532,696	1,754,836
Derivative instruments	5,844	0
Stock-based compensation		400
Asset retirement obligations	65,456	46,434
Liabilities subject to compromise	1,284,144
Commitments and contingencies (Note 14)
Stockholders' deficit:
Preferred stock, 600,000 shares authorized, none issued and outstanding	0	0
Additional paid in capital	425,231	431,307
Accumulated deficit	(1,467,398)	(1,051,678)
Total stockholders' deficit	(1,042,153)	(620,357)
Total liabilities and stockholders' deficit	845,987	1,181,313
Common Class A
Stockholders' deficit:
Common stock	4	4
Common Class B
Stockholders' deficit:
Common stock	3	3
Common Class C
Stockholders' deficit:
Common stock	2	2
Common Class E
Stockholders' deficit:
Common stock	5	5
Common Class F
Stockholders' deficit:
Common stock	0	0
Common Class G
Stockholders' deficit:
Common stock	$ 0	$ 0

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Preferred stock, shares authorized	600,000	600,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, shares outstanding	1,392,706	1,404,309
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	333,686	345,289
Common stock, shares outstanding	333,686	345,289
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, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Revenues - commodity sales	$ 252,152	$ 324,315	$ 681,557
Costs and expenses:
Lease operating	90,533	110,659	141,608
Transportation and processing	8,845	8,541	8,295
Production taxes	9,610	9,953	28,305
Depreciation, depletion and amortization	122,928	216,574	245,908
Loss on impairment of oil and gas assets	281,079	1,491,129	0
Loss on impairment of other assets	1,393	16,207	0
General and administrative	20,953	39,089	53,414
Liability management	9,396	0	0
Cost reduction initiatives	2,879	10,028	0
Total costs and expenses	547,616	1,902,180	477,530
Operating (loss) income	(295,464)	(1,577,865)	204,027
Non-operating (expense) income:
Interest expense	(64,242)	(112,400)	(104,241)
Gain on extinguishment of debt	0	31,590	0
Non-hedge derivative (losses) gains	(22,837)	145,288	231,320
Write-off of Senior Note issuance costs, discount and premium	(16,970)	0	0
Other income, net	411	2,324	2,630
Net non-operating (expense) income	(103,638)	66,802	129,709
Reorganization items, net	(16,720)	0	0
(Loss) income before income taxes	(415,822)	(1,511,063)	333,736
Income tax (benefit) expense	(102)	(177,219)	124,443
Net (loss) income	$ (415,720)	$ (1,333,844)	$ 209,293

Consolidated statements of stoc

Consolidated statements of stockholders' equity (deficit) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid in Capital	Retained Earnings (Accumulated Deficit)
Stockholders' equity, balance at beginning of the period at Dec. 31, 2013	$ 497,264	$ 14	$ 424,377	$ 72,873
Balance at beginning 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
Net income (loss)	209,293	0	0	209,293
Stockholders' equity, balance at end of the period at Dec. 31, 2014	$ 711,858	$ 14	429,678	282,166
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
Net income (loss)	(1,333,844)	0	0	(1,333,844)
Stockholders' equity, balance at end of the period at Dec. 31, 2015	$ (620,357)	$ 14	431,307	(1,051,678)
Balance at end of period (in shares) at Dec. 31, 2015	1,404,309	1,404,309
Restricted stock forfeited	(9,006)	(9,006)
Restricted stock repurchased		(2,597)
Stock-based compensation	$ (6,076)	$ 0	(6,076)	0
Net income (loss)	(415,720)	0	0	(415,720)
Stockholders' equity, balance at end of the period at Dec. 31, 2016	$ (1,042,153)	$ 14	$ 425,231	$ (1,467,398)
Balance at end of period (in shares) at Dec. 31, 2016	1,392,706	1,392,706

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net (loss) income	$ (415,720)	$ (1,333,844)	$ 209,293
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion, and amortization	122,928	216,574	245,908
Loss on impairment of assets	282,472	1,507,336	0
Write-off of Senior Note issuance costs, discount and premium	16,970	0	0
Deferred income taxes	0	(177,487)	123,891
Non-hedge derivative losses (gains)	22,837	(145,288)	(231,320)
Loss (gain) on sale of assets	117	(1,584)	(2,152)
Gain on extinguishment of debt	0	(31,590)	0
Other	3,611	6,057	4,294
Change in assets and liabilities
Accounts receivable	(9,243)	15,720	4,692
Inventories	3,576	(1,968)	(5,516)
Prepaid expenses and other assets	(1,620)	481	(750)
Accounts payable and accrued liabilities	25,987	(17,200)	(24,652)
Revenue distribution payable	509	(12,075)	(671)
Stock-based compensation	(5,257)	(5,524)	894
Net cash provided by operating activities	47,167	19,608	323,911
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(146,296)	(313,481)	(685,459)
Proceeds from asset dispositions	1,349	42,618	291,429
Proceeds from non-hedge derivative instruments	90,590	233,605	2,417
Cash in escrow	48	0	0
Derivative premiums paid and other	0	0	(20,609)
Net cash used in investing activities	(54,309)	(37,258)	(412,222)
Cash flows from financing activities
Proceeds from long-term debt	181,000	120,000	302,115
Repayment of long-term debt	(1,952)	(102,978)	(228,594)
Repurchase of Senior Notes	0	(9,995)	0
Principal payments under capital lease obligations	(2,491)	(2,400)	(2,313)
Payment of other financing fees	0	(1,404)	0
Net cash provided by financing activities	176,557	3,223	71,208
Net increase (decrease) in cash and cash equivalents	169,415	(14,427)	(17,103)
Cash and cash equivalents at beginning of period	17,065	31,492	48,595
Cash and cash equivalents at end of period	$ 186,480	$ 17,065	$ 31,492

Nature of operations and summar

Nature of operations and summary of significant accounting policies	12 Months Ended
	Dec. 31, 2016
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. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to March 21, 2017. As discussed in “Note 2—Chapter 11 reorganization” we filed voluntary petitions for bankruptcy relief and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence on March 21, 2017. 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; forecasting our effective income tax rate and 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, 2016, cash with a recorded balance totaling $36,502 and $48,023 was held at JP Morgan Chase Bank, N.A. and Arvest Bank, respectively. In addition, we also held cash equivalents in the form of treasury securities with a recorded balance of $101,127 at Arvest Wealth Management. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. We have restricted cash of $1,400 which is included in “Cash and cash equivalents” in our consolidated balance sheets. The restricted funds were maintained as a requirement during the pendency of our bankruptcy and were no longer restricted after emergence from bankruptcy. 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: 2016 2015 Joint interests $ 13,818 $ 14,149 Accrued commodity sales 31,304 21,645 Derivative settlements — 40,380 Other 1,657 3,329 Allowance for doubtful accounts (553 ) (503 ) $ 46,226 $ 79,000 Inventories Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. We evaluate our inventory each quarter and when there is evidence that the utility of our inventory, in their disposal in the ordinary course of business, will be less than cost, whether due to physical deterioration, obsolescence, changes in price levels, or other causes, we record an impairment loss for the difference. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following at December 31: 2016 2015 Equipment inventory $ 8,165 $ 11,470 Commodities 1,418 1,698 Inventory valuation allowance (2,232 ) (839 ) $ 7,351 $ 12,329 We recorded lower of cost or market adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. Year ended December 31, 2016 2015 2014 Inventory - lower of cost or market adjustment $ 1,393 $ 10,192 $ — Property and equipment Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently. Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows: Furniture and fixtures 10 years Automobiles and trucks 5 years Machinery and equipment 10 — 20 years Office and computer equipment 5 — 10 years Building and improvements 10 — 40 years Oil and natural gas properties Capitalized Costs . We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, 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. See “Note 15—Oil and natural gas activities” for further details of our unevaluated oil and natural gas properties. 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, 2016, 2015, and 2014 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 SEC. Due to the substantial decline of commodity prices that began in mid-2014 and which continue to remain low, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of each quarter beginning with the second quarter of 2015 through the second quarter of 2016, resulting in ceiling test write-downs in those periods. 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 related to four drilling rigs during the year ended December 31, 2015. The loss was recorded as a result of the deterioration in commodity prices and drilling activity whereby the value of such equipment had declined while utilizing third party equipment had become more cost effective. The loss is reflected in “Loss on impairment of other assets” in our consolidated statements of operations. In October 2016, the Company entered into an agreement for the sale of our four drilling rigs for a price of $2,000. The sale closed in January 2017. Our bankruptcy filing on May 9, 2016, (see “Note 2—Chapter 11 reorganization”) was an event that required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result of the bankruptcy. 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 income taxes including the expected impacts of our emergence from Chapter 11 bankruptcy proceedings on the amount and availability of our loss carryforwards to offset future taxable income. 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, 2016 and 2015, 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 2009 through 2016 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. The Company’s derivative instruments are not designated as hedges for accounting purposes, thus changes in the fair value of derivatives are reported immediately in “Non-hedge derivative (losses) gains” 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. 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, and our drilling rigs, which were sold subsequent to December 31, 2016. See “Note 8—Fair value measurements” for additional information regarding our fair value measurements. 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, 2016 and 2015, 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, 2016 and, 2015 our aggregate imbalance due to under production was approximately 0 MMcf and 0 MMcf, respectively. As of December 31, 2016 and 2015, our aggregate imbalance due to over production was approximately 1,218 MMcf and 1,253 MMcf, respectively, and a liability for gas imbalances of $1,405 and $1,303, 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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy. The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting. We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used. The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. See “Note 11—Deferred compensation” for additional information relating to stock-based compensation. Liability management Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations. Cost reduction initiatives Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows: Year ended December 31, 2016 2015 2014 One-time severance and termination benefits $ 2,772 $ 7,757 $ — Professional fees 107 2,271 — Total cost reduction initiatives expense $ 2,879 $ 10,028 $ — 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. In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria was met. The guidance was adopted on December 31, 2016 and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 2 — Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance. In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment required debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in us reclassifying our unamortized Senior Note issuance costs of $18,359 as of December 31, 2015, from “Other assets” to a reduction of long-term debt on the consolidated balance sheets. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. In August 2015, the FASB issued guidance that clarified the issue by allowing an entity to make an election to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance was adopted on January 1, 2016, in conjunction with the adoption of the initial guidance. We made an accounting policy election to present line-of-credit arrangement debt issuance costs as a deduction from the carrying amount of our line-of-credit arrangement. As a result of this election, we reclassified our unamortized Existing Credit Facility issuance costs as of December 31, 2016 and 2015, respectively, of $2,303 and $5,067 from “Other assets” to a reduction of long-term debt on the consolidated balance sheets. In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. 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. This guidance was early adopted on a prospective basis during the second quarter of 2016 and allowed us to offset our noncurrent deferred income tax asset with our current deferred income tax liability. Prior periods were not retrospectively adjusted. Other than the preceding balance sheet change, the adoption 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 updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The new standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and clarification to this topic including clarification on principal vs. agent considerations and identifying performance obligations and licensing. We are currently evaluating the effect the new standard and its subsequent updates will have on our financial statements and results of operations. In 2017, we established an implementation team (“team”) and engaged external advisers to develop a multi-phase plan to assess our business and contracts, as well as any changes to processes to adopt the requirements of the new standard and its related updates. 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 do not expect this guidance to materially impact our financial statements or 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. Furthermore, all 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, and should be applied using a modified retrospective approach. Early adoption is permitted. Based on an assessment of our current operating leases, which are predominantly comprised of leases for CO 2 In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter. Early adoption is permitted. We do not expect this guidance to materially impact our financial statements or results of operations in connection with our outstanding awards. In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC 815. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted in any interim period for which financial statements have not been issued, but would be retroactively applied to the beginning of the year that includes the interim period. We do not expect this guidance to materially impact our financial statements or results of operations. In June 2016, the FASB issued authoritative guidance

Chapter 11 Reorganization

Chapter 11 Reorganization	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Chapter 11 Reorganization	Note : Chapter 11 Reorganization Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”). On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy. Debtor-In-Possession. During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court. Automatic Stay. Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code. Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Existing Credit Facility (collectively, the “Lenders”) and certain holders of our Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date: • On the Effective Date, we issued approximately 45,000,000 shares of the reorganized company (“New Common Stock”), which were the result of the transactions described below. We also entered into a shareholders agreement and a registration rights agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide registration rights thereunder, among other corporate governance actions. See “Note 12—Stockholders' equity” for a discussion of our post emergence equity; • Our Predecessor common stock was cancelled, extinguished and discharged and the Predecessor equity holders did not receive any consideration in respect of their equity interests; • The $1,267,410 of indebtedness, including accrued interest, attributable to our Senior Notes were exchanged for New Common Stock. In addition, we reserved shares of New Common Stock to be exchanged in settlement of $2,981 of certain general unsecured claims. In aggregate, the shares of New Common Stock issued or to be issued in settlement of the Senior Note and these general unsecured claims represented approximately 90% percent of outstanding Successor common shares; • We completed a rights offering backstopped by certain holders of our Senior Notes (the “Backstop Parties”) which generated $50,000 of gross proceeds. The rights offering resulted in the issuance of New Common Stock, representing approximately nine percent of outstanding shares, to holders of claims arising under the Senior Notes and to the Backstop Parties; • In connection with the rights offering described above, the Backstop Parties received approximately one percent of outstanding New Common Stock as a backstop fee; • Additional shares, representing seven percent of outstanding New Common Stock, were authorized for issuance under a new management incentive plan; • Warrants to purchase 140,023 shares of New Common Stock were issued to Mr. Mark Fischer, our founder and former Chief Executive Officer, with an exercise price of $36.78 per share and expiring on June 30, 2018. The warrants were issued in exchange for consulting services provided by Mr. Fischer; • Our Existing Credit Facility, previously consisting of a senior secured revolving credit facility was restructured into a New Credit Facility consisting of a first-out revolving facility (“New Revolver”) and a second-out term loan (“New Term Loan”). On the Effective Date, the entire balance on the Existing Credit Facility in the amount of $444,440 was repaid while we received proceeds representing the opening balances on our New Revolver of $120,000 and a New Term Loan of $150,000. For more information refer to “Note 6—Debt;” • We paid $6,953 for creditor-related professional fees and also funded a $11,000 segregated account for debtor-related professional fees in connection with the reorganization related transactions above; • Certain other priority or convenience class claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claimholders; • Plaintiffs to one of our royalty owner litigation cases, which were identified as a separate class of creditors (Class 8) in our bankruptcy case, rejected the Reorganization Plan. If the claimants under Class 8 are permitted to file a class of proof claim on behalf of the putative class, certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgement or settlement of the claims would be satisfied through issuance of new stock in the Company. In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1,050,000 to $1,350,000 with a midpoint of $1,200,000, which was subsequently approved by the Bankruptcy Court. In accordance with the Reorganization Plan, our post-emergence new board of directors is made up of seven directors consisting of the Chief Executive Officer of the post-emergence Company (K. Earl Reynolds) and six members (including the chairman of the New Board). Our new board members are Mr. Robert Heineman, Mr. Douglas Brooks, Mr. Kenneth Moore, Mr. Matthew Cabell, Mr. Samuel Langford and Mr. Gysle Shellum Liabilities Subject to Compromise. In accordance with ASC 852 “Reorganizations,” our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on the Bankruptcy Court actions, further development with respect to disputed claims, and other events: December 31, 2016 Accounts payable and accrued liabilities $ 9,212 Accrued payroll and benefits payable 4,048 Revenue distribution payable 3,474 Senior Notes and associated accrued interest 1,267,410 Liabilities subject to compromise $ 1,284,144 Reorganization Items. We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred significant costs associated with the reorganization. Reorganization items for the year ended December 31, 2016, are as follows: Year Ended December 31, 2016 Professional fees $ 15,484 Claims for non-performance of executory contract 1,236 Total reorganization items $ 16,720 Fresh Start Accounting. In connection with our emergence from bankruptcy, we will be required to apply fresh start accounting to our financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims. Fresh start accounting will be applied to our consolidated financial statements as of the Effective Date. Under the principles of fresh start accounting, a new reporting entity was considered to be created, and, as a result, we will allocate the reorganization value of the Company to its individual assets based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Reorganization Plan, the enterprise value of the post emergence Company was estimated and approved by the Bankruptcy Court to be in the range of $1,050,000 to $1,350,000 with a midpoint of $1,200,000.

Supplemental disclosures to the

Supplemental disclosures to the consolidated statements of cash flows	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Net cash provided by operating activities included: Cash payments for interest $ 25,764 $ 116,379 $ 112,196 Interest capitalized (2,139 ) (9,670 ) (13,491 ) Cash payments for interest, net of amounts capitalized $ 23,625 $ 106,709 $ 98,705 Cash payments for income taxes $ 250 $ 640 $ 591 Cash payments for reorganization items $ 10,670 $ — $ — Non-cash financing activities included: Repayment of Existing Credit Facility with proceeds from early termination of derivative contracts (See Note 6) $ 103,560 $ — $ — Non-cash investing activities included: Asset retirement obligation additions and revisions $ 22,282 $ 4,000 $ 7,461 Change in accrued oil and gas capital expenditures $ (19,725 ) $ (105,312 ) $ 43,971

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and divestitures	Note 4: Acquisitions and divestitures 2016 Divestitures During 2016, we did not have any significant divestitures of our oil and natural gas properties. 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.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 Furniture and fixtures $ 2,518 $ 2,518 Automobiles and trucks 9,793 10,689 Machinery and equipment 53,757 55,963 Office and computer equipment 20,817 19,993 Building and improvements 25,085 25,534 111,970 114,697 Less accumulated depreciation and amortization 79,415 75,041 32,555 39,656 Land 8,792 9,306 $ 41,347 $ 48,962

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Note 6: Debt Chapter 11 Proceedings and Emergence The bankruptcy petition constituted an event of default with respect to the Company’s pre-petition Existing Credit Facility and Senior Notes. Prior to the petition date, these facilities were also in default as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our 2015 annual financial statements. The enforcement of any obligations under the Company’s pre-petition debt was automatically stayed as a result of the Chapter 11 Cases. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our Existing Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into a New Credit Facility consisting of a senior secured first-out revolving facility (“New Revolver”) and a senior secured second-out term loan (“New Term Loan”). Reclassification of Debt The balances outstanding under our Senior Notes were classified as liabilities subject to compromise on the accompanying consolidated balance sheets at December 31, 2016. The outstanding balances under our Existing Credit Facility, real estate mortgage notes, installment notes and capital leases were not classified as subject to compromise at December 31, 2016, as these obligations were secured. Furthermore, as a result of certain debt defaults discussed above, which occurred in early 2016 and remained uncured during the pendency of the Chapter 11 Cases, all outstanding long-term debt was classified as current as of December 31, 2015 and 2016. Pre-emergence Debt As of the dates indicated, debt consists of the following: December 31, 2016 2015 9.875% Senior Notes due 2020, net of discount of $0 and $4,185, respectively $ — $ 293,815 8.25% Senior Notes due 2021 — 384,045 7.625% Senior Notes due 2022, including premium of $0 and $4,939, respectively — 530,849 Existing Credit Facility 444,440 367,000 Real estate mortgage notes, principal and interest payable monthly, bearing interest at 5.46%, due December 2028; collateralized by real property 9,595 10,182 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.00%, due January 2017 through February 2018; collateralized by automobiles, machinery and equipment 434 1,799 Capital lease obligations 16,946 19,437 Unamortized issuance costs (1) (2,303 ) (23,426 ) Total debt, net 469,112 1,583,701 Less current portion 469,112 1,583,701 Total long-term debt, net $ — $ — (1) Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below. December 31, Unamortized debt issuance costs 2016 2015 9.875% Senior Notes due 2020 $ — $ 4,078 8.25% Senior Notes due 2021 — 5,459 7.625% Senior Notes due 2022 — 8,822 Existing Credit Facility 2,303 5,067 Total unamortized debt issuance costs $ 2,303 $ 23,426 We recorded amortization of our Senior Note debt issuance costs of $602, $1,921 and $2,335 for the years ended, December 31, 2016, 2015 and 2014, respectively. Absent any acceleration of our debt resulting from defaults or conversion to equity as a result of our Chapter 11 reorganization, the initial maturities of debt and capital leases would be as follows as of December 31, 2016: 2017 $ 448,033 2018 3,295 2019 12,321 2020 298,679 2021 384,762 2022 and thereafter 532,280 $ 1,679,370 Senior Notes The Senior Notes, as of December 31, 2016, are our senior unsecured obligations and 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 were 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 were payable semi-annually, and the principal was 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 $32, $945, and $(268) during the years ended December 31, 2016, 2015 and 2014, respectively. 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 for the year ended December 31, 2015. In March 2016 we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our 30-day grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount as follows: Year Ended December 31, 2016 Non-cash expense for write-off of debt issuance costs on Senior Notes $ 17,756 Non-cash expense for write-off of debt discount costs on Senior Notes 4,014 Non-cash gain for write-off of debt premium on Senior Notes (4,800 ) Total $ 16,970 Pursuant to accounting guidance, while in bankruptcy, we did not accrue interest expense on our Senior Notes during the pendency of the Chapter 11 Cases as we do not expect to pay such interest. As a result, reported interest expense is $65,225 lower than contractual interest for the year ended December 31, 2016. As discussed in “Note 2—Chapter 11 reorganization”, on the Effective Date, our obligations with respect to the Senior Notes, including principal and accrued interest, were cancelled and holders of the Senior Notes received their agreed-upon pro-rata share of the Company’s post-emergence equity. Existing Credit Facility In April 2010, we entered into an Eighth Restated Credit Agreement (the ‘Existing Credit Facility”), which is collateralized by our oil and natural gas properties and, as amended, was originally scheduled to mature on November 1, 2017. Availability under our Existing Credit Facility was subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually. The initial borrowing base on our Existing Credit Facility for 2016 was $550,000; however subsequent to the defaults on this facility in March 2016, we no longer had availability under the facility until our debt was restructured upon exiting bankruptcy. During 2016, we had additional borrowings of $181,000 and repayments of $103,560 on our Existing Credit Facility. As discussed in “Note 7—Derivative instruments,” our repayment of $103,560 was effectuated by directly offsetting proceeds payable to us from the termination of our derivative contracts against outstanding borrowings under the Existing Credit Facility during the third quarter of 2016. The ability to offset was possible as the previous counterparties to our derivative contracts were also lenders under the Existing Credit Facility. Amounts borrowed under our Existing 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, 2016 was subject to the ABR which resulted in a weighted average interest rate of 5.25% on the outstanding amount. This rate did not include an additional 2.00% default margin which was waived by the Lenders pursuant to our Reorganization Plan. Our Existing Credit Facility, as amended, also had certain negative and affirmative covenants that required, among other things, maintaining a Current Ratio, a Consolidated Net Secured Debt to Consolidated EBITDAX ratio and an Interest Coverage Ratio (all ratios as defined in the amendment). Subsequent to our debt defaults in March 2016 and through the pendency of our Chapter 11 Cases, we ceased quarterly reporting of our covenant compliance, which included these ratios, to the administrative agent of the facility. Pursuant to the Reorganization Plan and in conjunction with a repayment of the entire balance of $444,440 on the Effective Date, our Existing Credit Facility was amended and restated in its entirety by the New Credit Facility as discussed below. Post-emergence Debt As discussed above, our post-emergence exit financing consists of the New Credit Facility, which includes the New Revolver and the New Term Loan, which was entered into on the Effective Date. The initial outstanding amounts under the New Credit Facility were: March 21, 2017 New Term Loan, net of discount of $750 (1) $ 149,250 New Revolver 120,000 Unamortized debt issuance costs - New Revolver (1) (1,125 ) Total $ 268,125 (1) Upfront fees of 0.5% were paid to the lenders under the New Credit Facility. The amount paid in connection with the New Term Loan is reflected as a discount on the loan and will be amortized under the effective interest method. The amount paid in connection with the New Revolver will be reflected as a reduction to the liability whenever outstanding borrowings exceed the remaining unamortized issuance costs, otherwise such amount will be reflected as an asset. The issuance cost related to the New Revolver will be amortized ratably over the life of the facility. New Term Loan The New Term Loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate. We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity: 2017 $ 1,183 2018 1,500 2019 3,750 2020 6,750 Total mandatory prepayments $ 13,183 New Revolver The New Revolver, is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and 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 or upon the occurrence of certain specified events. 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 the Effective Date was $225,000 and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Revolver as of the Effective Date, after taking into account outstanding borrowings and letters of credit on that date, was $104,172. Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternate Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternate Base Rate plus an additional 2.00% and plus the applicable margin. 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 generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate. If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 45 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency. Other Provisions Interest payment dates are dependent on the type of borrowing. In the case of Alternate Base Rate loans, interest is payable quarterly in arrears. In the case of Adjusted LIBO Rate borrowings, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period. As a precedent condition under the New Credit Agreement, we were required to have $100,000 of Liquidity (as defined in the New Credit Facility) upon emergence from our Chapter 11 Cases. The New Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others. The financial covenants require, for each fiscal quarter ending on and after March 31, 2017, that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25,000 and (4) a Ratio Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis. The New Credit Facility is guaranteed by all of our wholly owned subsidiaries, subject to customary exceptions, and is secured by first priority security interests on substantially all of our assets. 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.

Derivative instruments

Derivative instruments	12 Months Ended
	Dec. 31, 2016
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, collars, put options, enhanced swaps 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, such as put options and collars, which are not costless but instead require payment of a premium. The 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. Commodity price swaps allow us to 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. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. 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. Enhanced swaps enhance the value of swaps by combining them with sold puts or put spread contracts. The use of a sold put or put spread allows us to receive an above-market swap price while also providing a measure of downside protection. 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. A put spread may also be constructed by entering into separate sold put and purchased put contracts. Basis protection swaps are used 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. Due to defaults under the master agreements governing our derivative contracts, our outstanding derivative positions were terminated in May 2016. 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 Existing Credit Facility. The derivative master agreements with these counterparties 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 December 2016, an agreement was reached with the Lenders regarding the resumption of hedging activity prior to our emergence from bankruptcy and thus we began entering into new derivative instruments. We entered into the bulk of our new derivative positions prior to December 31, 2016; however additional derivatives positions were entered into subsequent to year end. The following table summarizes our crude oil derivatives outstanding as of December 31, 2016: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Purchased puts Sold calls 2017 Swaps 3,631 $ 54.97 $ — $ — 2018 Swaps 2,116 $ 54.92 $ — $ — Collars 183 $ — $ 50.00 $ 60.50 2019 Swaps 1,204 $ 54.25 $ — $ — The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2016: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2017 Swaps 9,575 $ 3.34 2018 Swaps 5,861 $ 3.03 2019 Swaps 3,322 $ 2.86 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 MBbls of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our Existing 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. As discussed previously, our outstanding derivatives, as of May 2016, were early terminated as a result of our defaults under the master agreements governing our derivative contracts. These derivative contracts, originally scheduled to settle from 2016 through 2018, covered 3,400 MBbls of oil and 28,800 BBtu of natural gas. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119,303. Of this amount, in the third quarter of 2016, $103,560 was utilized to offset outstanding borrowings under our Existing Credit Facility and the remainder was remitted to the Company. During January 2017, we entered into additional oil and natural gas swap contracts. The following table summarizes the additional contracts: Period and type of contract Volume BBtu Volume MBbls Fixed price per MMBtu Fixed price per Bbl 2017 Natural gas swap 154 — $ 3.40 $ — 2019 Crude oil swap — 108 $ — $ 54.40 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, 2016 As of December 31, 2015 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 184 $ (3,658 ) $ (3,474 ) $ 41,328 $ (1,158 ) $ 40,170 Crude oil derivative contracts — (9,895 ) (9,895 ) 123,068 — 123,068 Total derivative instruments 184 (13,553 ) (13,369 ) 164,396 (1,158 ) 163,238 Less: Netting adjustments (1) 184 (184 ) — 1,158 (1,158 ) — Derivative instruments - current — (7,525 ) (7,525 ) 143,737 — 143,737 Derivative instruments - long-term $ — $ (5,844 ) $ (5,844 ) $ 19,501 $ — $ 19,501 (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 related to the same current versus noncurrent classification on the balance sheet. Effect of derivative instruments on the consolidated statements of operations We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative (losses) gains” in the consolidated statements of operations. “Non-hedge derivative (losses) gains” in the consolidated statements of operations is comprised of the following: 2016 2015 2014 Change in fair value of commodity price derivatives $ (176,607 ) $ (88,317 ) $ 228,903 Settlement gains on commodity price derivatives 62,626 218,210 2,417 Settlement gains on early terminations of commodity price derivatives 91,144 15,395 — Non-hedge derivative (losses) gains $ (22,837 ) $ 145,288 $ 231,320

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2016
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 had no Level 1 assets or liabilities as of December 31, 2016 or December 31, 2015. Our derivative contracts classified as Level 2 as of December 31, 2016 consisted of commodity price swaps and as of December 31, 2015 consisted of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from these derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at a rate that captures our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets. As of December 31, 2016 our derivative contracts classified as Level 3 consisted of collars. As of December 31, 2015, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, 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, 2016 As of December 31, 2015 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 184 $ (13,455 ) $ (13,271 ) $ 41,328 $ (1,158 ) $ 40,170 Significant unobservable inputs (Level 3) — (98 ) (98 ) 123,068 — 123,068 Netting adjustments (1) (184 ) 184 — (1,158 ) 1,158 — $ — $ (13,369 ) $ (13,369 ) $ 163,238 $ — $ 163,238 (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, 2016 and 2015 were: Net derivative assets (liabilities) 2016 2015 Beginning balance $ 123,068 $ 195,167 Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains (9,314 ) 105,055 Purchases — — Settlements received (113,852 ) (177,154 ) Ending balance $ (98 ) $ 123,068 (Losses) gains relating to instruments still held at the reporting date included in non- hedge derivative (losses) gains for the period $ (98 ) $ 61,260 Nonrecurring fair value measurements Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2016 and 2015 were escalated using an annual inflation rate of 2.42% and 2.91%, respectively, and discounted using our credit-adjusted risk-free interest rate of 17.05% and 15.09%, 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 of $6,015 during the second quarter of 2015 related to our four stacked drilling rigs and drill pipe. The estimated fair value related to the impairment assessment was primarily based on third party estimates and, therefore, was classified within Level 3 of the fair value hierarchy. No impairment was recognized on our drilling rigs for the years ended December 31, 2016 and 2014. As discussed in “Note 1—Nature of operations and summary of significant accounting policies,” our four drilling rigs were sold in January 2017. 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, 2016 and 2015 were as follows: December 31, 2016 December 31, 2015 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 298,000 $ 268,200 $ 293,815 $ 75,750 8.25% Senior Notes due 2021 384,045 344,680 384,045 96,956 7.625% Senior Notes due 2022 525,910 470,689 530,849 120,478 Existing Credit Facility (1) NA NA 367,000 367,000 Other secured debt 10,029 10,029 11,981 11,981 $ 1,217,984 $ 1,093,598 $ 1,587,690 $ 672,165 (1) We have not disclosed the fair value of outstanding amounts under our Existing Credit Facility as it was not practicable to obtain a reasonable estimate of such value while the Predecessor was in bankruptcy. The fair value of our Senior Notes was estimated based on quoted market prices. 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 Existing Credit Facility and our New 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 Existing Credit Facility can be offset against amounts owed to such counterparty lender under our Existing Credit Facility. As of December 31, 2016, the counterparties to our open derivative contracts consisted of four financial institutions, of which four were subject to our rights of offset under our Existing 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 Existing Credit Facility that are available to offset our net derivative assets due from counterparties that are lenders under our Existing 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 Existing Credit Facility Net amount As of December 31, 2016 Derivative assets $ 184 $ (184 ) $ — $ — $ — $ — Derivative liabilities (13,553 ) 184 (13,369 ) — — (13,369 ) $ (13,369 ) $ — $ (13,369 ) $ — $ — $ (13,369 ) 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 (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 Existing Credit Facility. Payment on our derivative contracts could be accelerated in the event of a default on our Existing Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $13,553 at December 31, 2016. 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: 2016 2015 2014 Coffeyville Resources LLC 19.3 % 14.5 % 14.0 % Valero Energy Corporation 15.6 % 20.7 % 23.7 % Phillips 66 Company 15.1 % 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, 2016
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, 2016 2015 Beginning balance $ 48,612 $ 47,424 Liabilities incurred in current period 3,918 1,861 Liabilities settled or disposed in current period (2,729 ) (6,472 ) Revisions in estimated cash flows 18,364 2,139 Accretion expense 3,972 3,660 Asset retirement obligations at end of period 72,137 48,612 Less current portion included in accounts payable and accrued liabilities 6,681 2,178 Asset retirement obligations, long-term $ 65,456 $ 46,434 Liabilities incurred include obligations related to new wells drilled and wells acquired during the period. Revisions in estimated cash flows for the year ended December 31, 2016 increased significantly when compared to the previous year. Approximately two-thirds of the increase resulted from shortening the estimated life of certain wells and the remaining third resulted from increasing our cost estimates for the plugging and abandonment of certain wells. Estimated lives were shortened as continued depressed commodity prices have diminished the prospects for any near term price recovery. Our cost estimates were increased as a result of recent experience on the complexity of plugging wells within the high pressure CO 2 We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,519 and $1,567 at December 31, 2016 and 2015, 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, 2016
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: 2016 2015 2014 Current income taxes Federal $ (10 ) $ (21 ) $ (22 ) State (92 ) 195 574 Total current income taxes (102 ) 174 552 Deferred income taxes Federal — (161,879 ) 115,699 State — (15,514 ) 8,192 Total deferred income taxes — (177,393 ) 123,891 Income tax (benefit) expense $ (102 ) $ (177,219 ) $ 124,443 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: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal benefit 4.1 % 3.1 % 2.6 % Statutory depletion — — (0.2 )% Valuation allowance (39.0 )% (26.5 )% — Other, net (0.1 )% 0.1 % (0.1 )% Effective tax rate — 11.7 % 37.3 % Components of the deferred tax assets and liabilities are as follows at December 31: 2016 2015 Deferred tax assets related to Asset retirement obligations $ 15,825 $ 14,669 Accrued expenses, allowance and other 31,711 11,564 Property and equipment 241,126 259,096 Inventories — 372 Derivative instruments 7,048 — Net operating loss carryforwards Federal 241,109 154,265 State 33,605 21,466 Statutory depletion carryforwards 4,158 3,962 Alternative minimum tax credit carryforwards 308 308 574,890 465,702 Less valuation allowance (574,338 ) (411,147 ) Deferred tax asset 552 54,555 Deferred tax liabilities related to Derivative instruments — (54,555 ) Inventories (552 ) — Deferred tax liability (552 ) (54,555 ) Net deferred tax liability $ — $ — 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. Due to the full cost ceiling impairments recognized during 2016, we maintained our deferred tax asset position at December 31, 2016. We believe that it is more likely than not that these deferred tax assets will not be realized and recorded a $163,191 increase in valuation allowance to $574,338 maintaining the full valuation allowance against our net deferred tax asset at December 31, 2016. In our view, our cumulative historical three year pre-tax loss for the three years ended December 31, 2016, outweighs the other subjective factors, such as the possibility of 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 valuation allowance totaling approximately $411,147 (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 December 31, 2015. 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 $689,000 at December 31, 2016, which will expire between 2028 and 2036 if not utilized in earlier periods. At December 31, 2016, we have state net operating loss carryforwards of approximately $844,000, which will expire between 2017 and 2036 if not utilized in earlier periods. In addition, at December 31, 2016 we had federal percentage depletion carryforwards of approximately $12,000, 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. The IRC provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Our emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC. However, the IRC provides alternatives for taxpayers emerging from a Chapter 11 bankruptcy proceeding that may mitigate or even eliminate an annual limitation. We are in the process of analyzing these alternatives in order to minimize the impact of the ownership change on its ability to utilize tax attributes in future periods. This analysis will be dependent on a number of factors, including verifying qualification for each alternative, analyzing the possibility of a second ownership change during the two year period following emergence, and analyzing transactions subsequent to emergence generating taxable gains or losses. We will make a final determination regarding the most beneficial alternative upon filing its 2017 U.S. Federal income tax return prior to its extended due date in the Fall of 2018. Important in the determination of the tax attributes of a debtor corporation following emergence from Chapter 11 is the amount of cancellation of indebtedness income realized. On the emergence date, as described in “Note 2—Chapter 11 reorganization,” pursuant to the Reorganization Plan, $1,267,410 of indebtedness, including accrued interest, attributable to our Senior Notes and $2,981 of general unsecured claims were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC of 1986, as amended provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. While we are currently in the process of finalizing the bankruptcy related calculations, it is our expectation that the fair market value of the consideration received by our creditors upon emergence is substantially the same as the adjusted issue price of the indebtedness extinguished. Accordingly, the amount of CODI realized upon emergence may be relatively low, possibly zero. However, to the extent the finally determined fair market value of the consideration is less than the adjusted issue price of the indebtedness, and CODI was realized, such amount of CODI would be excluded from taxable income and would reduce our prior tax attributes, which could include net operating losses, capital losses, alternative minimum tax credits and tax basis in assets. Any reduction of tax attributes is expected to be fully offset by a corresponding decrease in valuation allowance. Finally, any required reduction in tax attributes will not occur until the first day of our tax year ending subsequent to the date of emergence, or January 1, 2018.

Deferred compensation

Deferred compensation	12 Months Ended
	Dec. 31, 2016
Share Based Compensation [Abstract]
Deferred Compensation	Note 11: Deferred 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. We did not grant any Phantom Unit or RSUs awards during 2016 and all remaining unvested awards were cancelled upon our emergence from bankruptcy on the Effective Date. A summary of our phantom stock and RSU activity during the three years ended December 31, 2016 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, 2014 $ 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 Granted $ — — $ — — Vested $ 18.39 (9,729 ) $ — $ 9.01 (140,818 ) $ — Forfeited $ 21.09 (890 ) $ 8.23 (30,472 ) Unvested and outstanding at December 31, 2016 — $ 7.18 98,596 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, 2016 is $0.00. 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. Amounts related to our 2015 Cash LTIP are presented below: For the Year Ended December 31, 2016 2015 Long-Term Cash Incentive Plan Amount awarded $ — $ 3,297 Expense 1,008 610 Payments 666 — 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. Our bankruptcy filing in 2016 affected the valuation of our Time and Performance awards. Specifically, since our Reorganization Plan contemplates the cancellation of all existing common equity without any residual interest or consideration provided to the equity holders, the fair value of our Time and Performance awards was determined to be $0.00 per share as of the Petition Date. Prior to our bankruptcy, a combined income and market valuation methodology was used in the past to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2015, and 2014 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% and 20%, respectively. A control discount was not applied to the valuation pursuant to guidance released by the AICPA 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 Risk free interest rate 0.71 % to 1.44 % 0.25 % to 1.48 % Expected volatility 71 % to 81 % 52 % to 56 % Expected life 3 years 4 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, 2016 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, 2014 $ 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 Granted — — Vested $ 798.85 (5,279 ) $ 93 $ — — Forfeited $ 799.30 (2,033 ) $ 283.99 (6,973 ) Unvested and outstanding at December 31, 2016 $ 790.91 6,667 $ 277.33 21,475 During 2016, 2015, and 2014, respectively, we repurchased and canceled 2,597, 5,725, and 2,025 vested shares but we do not expect to repurchase any restricted shares prior to the cancellation of all Predecessor common stock upon our emergence from bankruptcy. Based on an estimated fair value of $0.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $0 as of December 31, 2016. 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: 2016 2015 2014 Stock-based compensation cost $ (6,196 ) $ (2,169 ) $ 6,235 Less: stock-based compensation cost capitalized 958 229 (2,346 ) Stock-based compensation (credit) expense $ (5,238 ) $ (1,940 ) $ 3,889 Recognized tax (expense) benefit associated with stock-based compensation $ — $ (229 ) $ 1,452 During the third quarter of 2016, we recorded a cumulative catch up adjustment of $5,985 to reverse the aggregate compensation cost associated with our Performance Vested awards in order to reflect a decrease in the probability that requisite service would be achieved for these awards. Expense during 2016 was a credit as a result of the aforementioned catch up adjustment, forfeitures and the reduction in fair value of our liability-based awards. Payments for stock-based compensation were $49, $3,991, and $2,995 during 2016, 2015, and 2014, respectively. As of December 31, 2016 and 2015, accrued payroll and benefits payable included $0 and $81, respectively, for stock-based compensation costs expected to be settled within the next twelve months. The remaining unrecognized stock-based compensation cost of approximately $207 as of December 31, 2016 is expected to be recognized in its entirety upon the cancellation of all Predecessor common stock on the Effective Date.

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2016
Stockholders Equity Note [Abstract]
Stockholders' equity	Note 12: Stockholders' equity Pre-emergence 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. 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. Since the respective rights under the different classes of common stock generally relate to capital transactions that are outside the ordinary course of business, such transactions have been under purview of the Bankruptcy Court during the pendency of the Chapter 11 Cases rather than at the discretion of the existing stockholders. On the Effective Date, all existing common stock of the Predecessor was cancelled and each holder of such stock did not receive any distribution or retain any property on account of their stock interest. Post-emergence Common Stock On the Effective Date, we issued or reserved for issuance a total of 45,000,000 shares of Successor common stock consisting of 37,125,000 shares of Class A common stock and 7,875,000 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents. The new Class A shares and Class B shares have identical economic and voting rights, except that the new Class B shares shall be subject to certain redemption provisions in the event the Company undertakes an initial public offering. 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, 2016, 2015 and 2014. Common Stock Class A Class B Class C Class D Class E Class F Class G Total Shares issued at January 1, 2014 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 Restricted stock issuance — — — — — — — — Restricted stock repurchased (2,597 ) — — — — — — (2,597 ) Restricted stock forfeited (9,006 ) — — — — — — (9,006 ) Shares issued at December 31, 2016 333,686 344,859 209,882 — 504,276 1 2 1,392,706 (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, 2016
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 2016, 2015 and 2014. At December 31, 2016, 2015, and 2014, there were 315, 395, and 625 employees, respectively, participating in the plan. Our contribution expense was $1,781, $2,363, and $3,592 for the years ended December 31, 2016, 2015 and 2014, respectively.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and contingencies	Note 14: Commitments and contingencies Letters of Credit. Standby letters of credit (“Letters”) available under our Existing Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. Our outstanding letters of credit, as of both December 31, 2016 and 2015, totaled $828. 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, 2016, 2015, or 2014. Commitments. We have three long-term contracts with three different suppliers to purchase CO 2 As of December 31, 2016, we were purchasing approximately 43 MMcf/d of CO 2 Based on current prices, our estimated minimum purchase obligations under our CO 2 2017 $ 1,386 2018 1,690 2019 1,934 2020 1,934 2021 1,934 2022 and thereafter 2,665 $ 11,543 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, 2016, total remaining payments associated with our operating leases were: 2017 $ 1,369 2018 1,367 2019 1,362 2020 1,330 2021 1,292 2022 and thereafter 479 $ 7,199 Litigation and Claims Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed through the Bankruptcy proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst 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 outcomes of the matters. As a result, no reserves have been established within our liabilities subject to compromise in connection with the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, such claims will be satisfied through the issuance of new stock in the Company. 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 Trial Court”) 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 (“Naylor Farms Case”). 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. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. Responsive briefs to both motions were filed in the fourth quarter of 2015. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. In response, on May 23, 2016, the court issued an order administratively closing the case, subject to reopening depending on the disposition of the bankruptcy proceedings. On July 22, 2016, attorneys for the putative class filed a motion in the Bankruptcy Court asking the court to lift the automatic stay and allow the case to proceed in the Naylor Trial Court. We did not object to lifting the automatic stay with regard to this case for the limited purpose of allowing the Naylor Trial Court to rule on the pending motion for class certification. On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the Plaintiffs originally sought to certify. On January 30, 2017, the Company filed a motion for reconsideration with the Naylor Trial Court, asking the court to rule the class cannot be immediately certified because Plaintiffs did not define dates for class membership. The plaintiffs 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. In addition to filing claims on behalf of the named plaintiffs and associated parties, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $150,000 in our Chapter 11 Cases. The Company has objected treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. The Bankruptcy Court heard testimony and argument regarding class-wide treatment of the claim on February 28, 2017, but has not ruled on the matter. Under the Reorganization Plan, the Plaintiffs are identified as a separate class of creditors, Class 8. The Plaintiffs voted to reject the Reorganization Plan. Under the Reorganization Plan, Class 8 claims are entitled to receive their pro rata 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 an allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include claims 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 the time we filed our Bankruptcy Petitions, a class had not been certified and discovery had not yet commenced. As the plaintiffs in the Dodson case did not file proofs of claim either for the putative class or the putative class representative, we anticipate any liability related to this claim will be addressed only based on proofs of claim filed by individual royalty owners. 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 challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies allegedly required under the National Environmental Protection (NEPA). 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. On March 31, 2016, the Court dismissed the case against the federal agencies named as defendants, and therefore against all defendants, as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed a motion to alter or amend the court’s opinion and vacate the judgment, arguing the court does have jurisdiction to hear the claims and dismissal of the federal defendants does not require dismissal of the oil company defendants. The plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. Several defendants have filed briefs objecting to plaintiffs’ motions. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code, and has not responded to the plaintiffs’ motions. After a motion for reconsideration was denied, Plaintiffs filed a Notice of Appeal on December 6, 2016. On December 30, 2016, the Court of Appeals entered an Order Abating Appeal due to pending bankruptcy proceedings of multiple defendants. On January 13, 2017 Plaintiffs responded to the Order Abating Appeal, asking the Court to proceed with the appeal. The court has not ruled on the appeal as of the date of this report. As the plaintiffs in the Donelson case did not file proofs of claim either for the putative class or the putative class representatives, we anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action. 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 eight counties in central 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 that our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs did not ask for damages related to actual property damage which may have occurred. We 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. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act (“CAFA”). On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Although we are named as a defendant, the Amended Complaint expressly limits its claims against us to those asserted in the original petition unless and until the automatic stay is lifted. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. Other defendants have filed motions to dismiss the action based on various theories. The court has not ruled on these motions. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, 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. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. 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, 2016
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: 2016 2015 2014 Property acquisition costs Proved properties $ 390 $ 1,192 $ 3,496 Unproved properties 15,497 24,735 84,938 Total acquisition costs 15,887 25,927 88,434 Development costs 114,472 150,261 561,578 Exploration costs 19,055 33,091 90,146 Total $ 149,414 $ 209,279 $ 740,158 Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows for the years ended December 31: 2016 2015 2014 DD&A $ 111,793 $ 204,692 $ 231,761 DD&A per BOE: $ 12.52 $ 20.07 $ 21.10 Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed. Year incurred 2016 2015 Total Leasehold acquisitions $ 14,170 $ 1,285 $ 15,455 Capitalized interest 1,356 538 1,894 Wells and facilities in progress of completion 3,004 — 3,004 Total unevaluated oil and natural gas properties excluded from amortization $ 18,530 $ 1,823 $ 20,353 The wells and facilities in progress of completion were completed in 2017 and transferred to the amortization base while we expect to complete our evaluation for the majority of the leasehold acreage costs 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, 2016
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, 2016 are as follows: Oil (MBbls) Natural gas (MMcf) Natural gas liquids (MBbls) Total (MBoe) Proved developed and undeveloped reserves As of January 1, 2014 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 Extensions and discoveries 4,037 18,085 1,499 8,550 Revisions (1) (16,312 ) (44,965 ) (57 ) (23,864 ) Production (4,870 ) (15,889 ) (1,408 ) (8,926 ) Balance at December 31, 2016 96,621 135,449 12,105 131,301 Proved developed reserves: January 1, 2014 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 December 31, 2016 28,590 108,800 9,352 56,076 Proved undeveloped reserves: January 1, 2014 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 December 31, 2016 68,031 26,649 2,753 75,225 (1) The downward revision in our reserves during 2016 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, revision in the base water flood decline curve at our North Burbank Unit, and the decline in SEC pricing. 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 were not expected to be developed within five-years and a decline in the estimated sales margin on 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, 2016 2015 2014 Future cash flows $ 4,635,481 $ 6,327,363 $ 11,275,090 Future production costs (1,998,001 ) (2,670,692 ) (3,605,107 ) Future development and abandonment costs (1,147,390 ) (1,536,063 ) (1,726,955 ) Future income tax provisions — (89,999 ) (1,487,121 ) Net future cash flows 1,490,090 2,030,609 4,455,907 Less effect of 10% discount factor (961,309 ) (1,345,920 ) (2,561,207 ) Standardized measure of discounted future net cash flows $ 528,781 $ 684,689 $ 1,894,700 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, 2016 2015 2014 Beginning of year $ 684,689 $ 1,894,700 $ 1,743,772 Sale of oil and natural gas produced, net of production costs (141,732 ) (196,319 ) (502,928 ) Net changes in prices and production costs (296,299 ) (2,230,601 ) 116,977 Extensions and discoveries 79,990 101,384 286,500 Improved recoveries — 524,436 148,673 Changes in future development costs 278,653 204,199 (91,027 ) Development costs incurred during the period that reduced future development costs 63,894 80,103 316,490 Revisions of previous quantity estimates (1) (223,218 ) (495,794 ) (40,481 ) Purchases and sales of reserves in place, net — (47,079 ) (278,825 ) Accretion of discount 68,545 237,134 223,324 Net change in income taxes 21,139 605,766 (46,584 ) Changes in production rates and other (6,880 ) 6,760 18,809 End of year $ 528,781 $ 684,689 $ 1,894,700 (1) Amounts in 2016 are primarily the result of removing proved undeveloped reserves that are not expected to be developed within the five years, a revision in the base water flood decline curve at our North Burbank Unit and the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. Amounts in 2015 are primarily the result of the decrease in SEC pricing, 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. 2016 2015 2014 Oil (per Bbl) $ 42.75 $ 50.28 $ 94.99 Natural gas (per Mcf) $ 2.49 $ 2.58 $ 4.35 Natural gas liquids (per Bbl) $ 13.47 $ 15.84 $ 36.10

Nature of operations and summ23

Nature of operations and summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2016
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. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to March 21, 2017. As discussed in “Note 2—Chapter 11 reorganization” we filed voluntary petitions for bankruptcy relief and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence on March 21, 2017.
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; forecasting our effective income tax rate and 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, 2016, cash with a recorded balance totaling $36,502 and $48,023 was held at JP Morgan Chase Bank, N.A. and Arvest Bank, respectively. In addition, we also held cash equivalents in the form of treasury securities with a recorded balance of $101,127 at Arvest Wealth Management. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. We have restricted cash of $1,400 which is included in “Cash and cash equivalents” in our consolidated balance sheets. The restricted funds were maintained as a requirement during the pendency of our bankruptcy and were no longer restricted after emergence from bankruptcy.
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: 2016 2015 Joint interests $ 13,818 $ 14,149 Accrued commodity sales 31,304 21,645 Derivative settlements — 40,380 Other 1,657 3,329 Allowance for doubtful accounts (553 ) (503 ) $ 46,226 $ 79,000
Inventories	Inventories Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. We evaluate our inventory each quarter and when there is evidence that the utility of our inventory, in their disposal in the ordinary course of business, will be less than cost, whether due to physical deterioration, obsolescence, changes in price levels, or other causes, we record an impairment loss for the difference. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following at December 31: 2016 2015 Equipment inventory $ 8,165 $ 11,470 Commodities 1,418 1,698 Inventory valuation allowance (2,232 ) (839 ) $ 7,351 $ 12,329 We recorded lower of cost or market adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. Year ended December 31, 2016 2015 2014 Inventory - lower of cost or market adjustment $ 1,393 $ 10,192 $ —
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 exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities. The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties. See “Note 15—Oil and natural gas activities” for further details of our unevaluated oil and natural gas properties. 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, 2016, 2015, and 2014 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 SEC. Due to the substantial decline of commodity prices that began in mid-2014 and which continue to remain low, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of each quarter beginning with the second quarter of 2015 through the second quarter of 2016, resulting in ceiling test write-downs in those periods. 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 related to four drilling rigs during the year ended December 31, 2015. The loss was recorded as a result of the deterioration in commodity prices and drilling activity whereby the value of such equipment had declined while utilizing third party equipment had become more cost effective. The loss is reflected in “Loss on impairment of other assets” in our consolidated statements of operations. In October 2016, the Company entered into an agreement for the sale of our four drilling rigs for a price of $2,000. The sale closed in January 2017. Our bankruptcy filing on May 9, 2016, (see “Note 2—Chapter 11 reorganization”) was an event that required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result of the bankruptcy.
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 income taxes including the expected impacts of our emergence from Chapter 11 bankruptcy proceedings on the amount and availability of our loss carryforwards to offset future taxable income. 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, 2016 and 2015, 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 2009 through 2016 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. The Company’s derivative instruments are not designated as hedges for accounting purposes, thus changes in the fair value of derivatives are reported immediately in “Non-hedge derivative (losses) gains” 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. 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, and our drilling rigs, which were sold subsequent to December 31, 2016. See “Note 8—Fair value measurements” for additional information regarding our fair value measurements.
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, 2016 and 2015, 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, 2016 and, 2015 our aggregate imbalance due to under production was approximately 0 MMcf and 0 MMcf, respectively. As of December 31, 2016 and 2015, our aggregate imbalance due to over production was approximately 1,218 MMcf and 1,253 MMcf, respectively, and a liability for gas imbalances of $1,405 and $1,303, 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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy. The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting. We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used. The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. See “Note 11—Deferred compensation” for additional information relating to stock-based compensation.
Liability management	Liability management Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.
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 depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows: Year ended December 31, 2016 2015 2014 One-time severance and termination benefits $ 2,772 $ 7,757 $ — Professional fees 107 2,271 — Total cost reduction initiatives expense $ 2,879 $ 10,028 $ —
Recently issued and adopted 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. In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria was met. The guidance was adopted on December 31, 2016 and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 2 — Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance. In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment required debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in us reclassifying our unamortized Senior Note issuance costs of $18,359 as of December 31, 2015, from “Other assets” to a reduction of long-term debt on the consolidated balance sheets. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. In August 2015, the FASB issued guidance that clarified the issue by allowing an entity to make an election to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance was adopted on January 1, 2016, in conjunction with the adoption of the initial guidance. We made an accounting policy election to present line-of-credit arrangement debt issuance costs as a deduction from the carrying amount of our line-of-credit arrangement. As a result of this election, we reclassified our unamortized Existing Credit Facility issuance costs as of December 31, 2016 and 2015, respectively, of $2,303 and $5,067 from “Other assets” to a reduction of long-term debt on the consolidated balance sheets. In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. 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. This guidance was early adopted on a prospective basis during the second quarter of 2016 and allowed us to offset our noncurrent deferred income tax asset with our current deferred income tax liability. Prior periods were not retrospectively adjusted. Other than the preceding balance sheet change, the adoption 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 updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The new standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and clarification to this topic including clarification on principal vs. agent considerations and identifying performance obligations and licensing. We are currently evaluating the effect the new standard and its subsequent updates will have on our financial statements and results of operations. In 2017, we established an implementation team (“team”) and engaged external advisers to develop a multi-phase plan to assess our business and contracts, as well as any changes to processes to adopt the requirements of the new standard and its related updates. 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 do not expect this guidance to materially impact our financial statements or 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. Furthermore, all 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, and should be applied using a modified retrospective approach. Early adoption is permitted. Based on an assessment of our current operating leases, which are predominantly comprised of leases for CO 2 In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter. Early adoption is permitted. We do not expect this guidance to materially impact our financial statements or results of operations in connection with our outstanding awards. In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC 815. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted in any interim period for which financial statements have not been issued, but would be retroactively applied to the beginning of the year that includes the interim period. We do not expect this guidance to materially impact our financial statements or results of operations. In June 2016, the FASB issued authoritative guidance which modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2020, however early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions we are permitted to take such as netting past due amounts against revenue and assuming title to the working interest, we do not expect this guidance to materially impact our financial statements or results of operations. In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. Early adoption is permitted. We do not expect this guidance to have a material impact on our consolidated statement of cash flows.
Liabilities Subject to Compromise	Liabilities Subject to Compromise. In accordance with ASC 852 “Reorganizations,” our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on the Bankruptcy Court actions, further development with respect to disputed claims, and other events: December 31, 2016 Accounts payable and accrued liabilities $ 9,212 Accrued payroll and benefits payable 4,048 Revenue distribution payable 3,474 Senior Notes and associated accrued interest 1,267,410 Liabilities subject to compromise $ 1,284,144
Reorganization Items	Reorganization Items. We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred significant costs associated with the reorganization. Reorganization items for the year ended December 31, 2016, are as follows: Year Ended December 31, 2016 Professional fees $ 15,484 Claims for non-performance of executory contract 1,236 Total reorganization items $ 16,720
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 summ24

Nature of operations and summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Components of accounts receivable	Accounts receivable consisted of the following at December 31: 2016 2015 Joint interests $ 13,818 $ 14,149 Accrued commodity sales 31,304 21,645 Derivative settlements — 40,380 Other 1,657 3,329 Allowance for doubtful accounts (553 ) (503 ) $ 46,226 $ 79,000
Components of inventory	Inventories consisted of the following at December 31: 2016 2015 Equipment inventory $ 8,165 $ 11,470 Commodities 1,418 1,698 Inventory valuation allowance (2,232 ) (839 ) $ 7,351 $ 12,329
Adjustments to inventory	We recorded lower of cost or market adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. Year ended December 31, 2016 2015 2014 Inventory - lower of cost or market adjustment $ 1,393 $ 10,192 $ —
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
Components of cost reduction initiatives expense	The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows: Year ended December 31, 2016 2015 2014 One-time severance and termination benefits $ 2,772 $ 7,757 $ — Professional fees 107 2,271 — Total cost reduction initiatives expense $ 2,879 $ 10,028 $ —

Chapter 11 Reorganization (Tabl

Chapter 11 Reorganization (Tables)	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Summary of Components of Liabilities Subject to Compromise	The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on the Bankruptcy Court actions, further development with respect to disputed claims, and other events: December 31, 2016 Accounts payable and accrued liabilities $ 9,212 Accrued payroll and benefits payable 4,048 Revenue distribution payable 3,474 Senior Notes and associated accrued interest 1,267,410 Liabilities subject to compromise $ 1,284,144
Reorganization Items	Reorganization items for the year ended December 31, 2016, are as follows: Year Ended December 31, 2016 Professional fees $ 15,484 Claims for non-performance of executory contract 1,236 Total reorganization items $ 16,720

Supplemental disclosures to t26

Supplemental disclosures to the consolidated statements of cash flows (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 Net cash provided by operating activities included: Cash payments for interest $ 25,764 $ 116,379 $ 112,196 Interest capitalized (2,139 ) (9,670 ) (13,491 ) Cash payments for interest, net of amounts capitalized $ 23,625 $ 106,709 $ 98,705 Cash payments for income taxes $ 250 $ 640 $ 591 Cash payments for reorganization items $ 10,670 $ — $ — Non-cash financing activities included: Repayment of Existing Credit Facility with proceeds from early termination of derivative contracts (See Note 6) $ 103,560 $ — $ — Non-cash investing activities included: Asset retirement obligation additions and revisions $ 22,282 $ 4,000 $ 7,461 Change in accrued oil and gas capital expenditures $ (19,725 ) $ (105,312 ) $ 43,971

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Components of Property and Equipment	Major classes of property and equipment consist of the following at December 31: 2016 2015 Furniture and fixtures $ 2,518 $ 2,518 Automobiles and trucks 9,793 10,689 Machinery and equipment 53,757 55,963 Office and computer equipment 20,817 19,993 Building and improvements 25,085 25,534 111,970 114,697 Less accumulated depreciation and amortization 79,415 75,041 32,555 39,656 Land 8,792 9,306 $ 41,347 $ 48,962

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Components of debt	As of the dates indicated, debt consists of the following: December 31, 2016 2015 9.875% Senior Notes due 2020, net of discount of $0 and $4,185, respectively $ — $ 293,815 8.25% Senior Notes due 2021 — 384,045 7.625% Senior Notes due 2022, including premium of $0 and $4,939, respectively — 530,849 Existing Credit Facility 444,440 367,000 Real estate mortgage notes, principal and interest payable monthly, bearing interest at 5.46%, due December 2028; collateralized by real property 9,595 10,182 Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.00%, due January 2017 through February 2018; collateralized by automobiles, machinery and equipment 434 1,799 Capital lease obligations 16,946 19,437 Unamortized issuance costs (1) (2,303 ) (23,426 ) Total debt, net 469,112 1,583,701 Less current portion 469,112 1,583,701 Total long-term debt, net $ — $ — (1) Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below. December 31, Unamortized debt issuance costs 2016 2015 9.875% Senior Notes due 2020 $ — $ 4,078 8.25% Senior Notes due 2021 — 5,459 7.625% Senior Notes due 2022 — 8,822 Existing Credit Facility 2,303 5,067 Total unamortized debt issuance costs $ 2,303 $ 23,426
Initial maturities of debt and capital leases	Absent any acceleration of our debt resulting from defaults or conversion to equity as a result of our Chapter 11 reorganization, the initial maturities of debt and capital leases would be as follows as of December 31, 2016: 2017 $ 448,033 2018 3,295 2019 12,321 2020 298,679 2021 384,762 2022 and thereafter 532,280 $ 1,679,370
Premiums, discounts and debt issuance costs	As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount as follows: Year Ended December 31, 2016 Non-cash expense for write-off of debt issuance costs on Senior Notes $ 17,756 Non-cash expense for write-off of debt discount costs on Senior Notes 4,014 Non-cash gain for write-off of debt premium on Senior Notes (4,800 ) Total $ 16,970
Schedule of initial outstanding amounts under new credit facility	The initial outstanding amounts under the New Credit Facility were: March 21, 2017 New Term Loan, net of discount of $750 (1) $ 149,250 New Revolver 120,000 Unamortized debt issuance costs - New Revolver (1) (1,125 ) Total $ 268,125 (1) Upfront fees of 0.5% were paid to the lenders under the New Credit Facility. The amount paid in connection with the New Term Loan is reflected as a discount on the loan and will be amortized under the effective interest method. The amount paid in connection with the New Revolver will be reflected as a reduction to the liability whenever outstanding borrowings exceed the remaining unamortized issuance costs, otherwise such amount will be reflected as an asset. The issuance cost related to the New Revolver will be amortized ratably over the life of the facility.
Schedule of mandatory principal payment according to schedule of remaining outstanding balance due upon maturity	We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity: 2017 $ 1,183 2018 1,500 2019 3,750 2020 6,750 Total mandatory prepayments $ 13,183

Derivative instruments (Tables)

Derivative instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of derivatives outstanding	The following table summarizes our crude oil derivatives outstanding as of December 31, 2016: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Purchased puts Sold calls 2017 Swaps 3,631 $ 54.97 $ — $ — 2018 Swaps 2,116 $ 54.92 $ — $ — Collars 183 $ — $ 50.00 $ 60.50 2019 Swaps 1,204 $ 54.25 $ — $ — The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2016: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2017 Swaps 9,575 $ 3.34 2018 Swaps 5,861 $ 3.03 2019 Swaps 3,322 $ 2.86 The following table summarizes the additional contracts: Period and type of contract Volume BBtu Volume MBbls Fixed price per MMBtu Fixed price per Bbl 2017 Natural gas swap 154 — $ 3.40 $ — 2019 Crude oil swap — 108 $ — $ 54.40
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, 2016 As of December 31, 2015 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 184 $ (3,658 ) $ (3,474 ) $ 41,328 $ (1,158 ) $ 40,170 Crude oil derivative contracts — (9,895 ) (9,895 ) 123,068 — 123,068 Total derivative instruments 184 (13,553 ) (13,369 ) 164,396 (1,158 ) 163,238 Less: Netting adjustments (1) 184 (184 ) — 1,158 (1,158 ) — Derivative instruments - current — (7,525 ) (7,525 ) 143,737 — 143,737 Derivative instruments - long-term $ — $ (5,844 ) $ (5,844 ) $ 19,501 $ — $ 19,501 (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 related to the same current versus noncurrent classification on the balance sheet.
Non-hedge derivative gains (losses) in the consolidated statements of operations	“Non-hedge derivative (losses) gains” in the consolidated statements of operations is comprised of the following: 2016 2015 2014 Change in fair value of commodity price derivatives $ (176,607 ) $ (88,317 ) $ 228,903 Settlement gains on commodity price derivatives 62,626 218,210 2,417 Settlement gains on early terminations of commodity price derivatives 91,144 15,395 — Non-hedge derivative (losses) gains $ (22,837 ) $ 145,288 $ 231,320

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 As of December 31, 2015 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 184 $ (13,455 ) $ (13,271 ) $ 41,328 $ (1,158 ) $ 40,170 Significant unobservable inputs (Level 3) — (98 ) (98 ) 123,068 — 123,068 Netting adjustments (1) (184 ) 184 — (1,158 ) 1,158 — $ — $ (13,369 ) $ (13,369 ) $ 163,238 $ — $ 163,238 (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, 2016 and 2015 were: Net derivative assets (liabilities) 2016 2015 Beginning balance $ 123,068 $ 195,167 Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains (9,314 ) 105,055 Purchases — — Settlements received (113,852 ) (177,154 ) Ending balance $ (98 ) $ 123,068 (Losses) gains relating to instruments still held at the reporting date included in non- hedge derivative (losses) gains for the period $ (98 ) $ 61,260
Fair value of other financial instruments	The carrying value and estimated fair value of our debt at December 31, 2016 and 2015 were as follows: December 31, 2016 December 31, 2015 Level 2 Carrying value Estimated fair value Carrying value Estimated fair value 9.875% Senior Notes due 2020 $ 298,000 $ 268,200 $ 293,815 $ 75,750 8.25% Senior Notes due 2021 384,045 344,680 384,045 96,956 7.625% Senior Notes due 2022 525,910 470,689 530,849 120,478 Existing Credit Facility (1) NA NA 367,000 367,000 Other secured debt 10,029 10,029 11,981 11,981 $ 1,217,984 $ 1,093,598 $ 1,587,690 $ 672,165 (1) We have not disclosed the fair value of outstanding amounts under our Existing Credit Facility as it was not practicable to obtain a reasonable estimate of such value while the Predecessor was in bankruptcy.
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 Existing Credit Facility that are available to offset our net derivative assets due from counterparties that are lenders under our Existing 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 Existing Credit Facility Net amount As of December 31, 2016 Derivative assets $ 184 $ (184 ) $ — $ — $ — $ — Derivative liabilities (13,553 ) 184 (13,369 ) — — (13,369 ) $ (13,369 ) $ — $ (13,369 ) $ — $ — $ (13,369 ) 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 (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.
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: 2016 2015 2014 Coffeyville Resources LLC 19.3 % 14.5 % 14.0 % Valero Energy Corporation 15.6 % 20.7 % 23.7 % Phillips 66 Company 15.1 % 11.8 % * * Less than 10%

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 Beginning balance $ 48,612 $ 47,424 Liabilities incurred in current period 3,918 1,861 Liabilities settled or disposed in current period (2,729 ) (6,472 ) Revisions in estimated cash flows 18,364 2,139 Accretion expense 3,972 3,660 Asset retirement obligations at end of period 72,137 48,612 Less current portion included in accounts payable and accrued liabilities 6,681 2,178 Asset retirement obligations, long-term $ 65,456 $ 46,434

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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: 2016 2015 2014 Current income taxes Federal $ (10 ) $ (21 ) $ (22 ) State (92 ) 195 574 Total current income taxes (102 ) 174 552 Deferred income taxes Federal — (161,879 ) 115,699 State — (15,514 ) 8,192 Total deferred income taxes — (177,393 ) 123,891 Income tax (benefit) expense $ (102 ) $ (177,219 ) $ 124,443
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: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State income taxes, net of federal benefit 4.1 % 3.1 % 2.6 % Statutory depletion — — (0.2 )% Valuation allowance (39.0 )% (26.5 )% — Other, net (0.1 )% 0.1 % (0.1 )% Effective tax rate — 11.7 % 37.3 %
Components of deferred tax assets and liabilities	Components of the deferred tax assets and liabilities are as follows at December 31: 2016 2015 Deferred tax assets related to Asset retirement obligations $ 15,825 $ 14,669 Accrued expenses, allowance and other 31,711 11,564 Property and equipment 241,126 259,096 Inventories — 372 Derivative instruments 7,048 — Net operating loss carryforwards Federal 241,109 154,265 State 33,605 21,466 Statutory depletion carryforwards 4,158 3,962 Alternative minimum tax credit carryforwards 308 308 574,890 465,702 Less valuation allowance (574,338 ) (411,147 ) Deferred tax asset 552 54,555 Deferred tax liabilities related to Derivative instruments — (54,555 ) Inventories (552 ) — Deferred tax liability (552 ) (54,555 ) Net deferred tax liability $ — $ —

Deferred compensation (Tables)

Deferred compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Share Based Compensation [Abstract]
Rollforward of unvested deferred compensation	A summary of our phantom stock and RSU activity during the three years ended December 31, 2016 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, 2014 $ 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 Granted $ — — $ — — Vested $ 18.39 (9,729 ) $ — $ 9.01 (140,818 ) $ — Forfeited $ 21.09 (890 ) $ 8.23 (30,472 ) Unvested and outstanding at December 31, 2016 — $ 7.18 98,596 A summary of our Time and Performance award activity during the three years ended December 31, 2016 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, 2014 $ 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 Granted — — Vested $ 798.85 (5,279 ) $ 93 $ — — Forfeited $ 799.30 (2,033 ) $ 283.99 (6,973 ) Unvested and outstanding at December 31, 2016 $ 790.91 6,667 $ 277.33 21,475
Summary of amounts related to 2015 cash LTIP	Amounts related to our 2015 Cash LTIP are presented below: For the Year Ended December 31, 2016 2015 Long-Term Cash Incentive Plan Amount awarded $ — $ 3,297 Expense 1,008 610 Payments 666 —
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 Risk free interest rate 0.71 % to 1.44 % 0.25 % to 1.48 % Expected volatility 71 % to 81 % 52 % to 56 % Expected life 3 years 4 years Expected dividends $ — $ —
Stock-based compensation cost	We recognized stock-based compensation expense as follows for the years ended December 31: 2016 2015 2014 Stock-based compensation cost $ (6,196 ) $ (2,169 ) $ 6,235 Less: stock-based compensation cost capitalized 958 229 (2,346 ) Stock-based compensation (credit) expense $ (5,238 ) $ (1,940 ) $ 3,889 Recognized tax (expense) benefit associated with stock-based compensation $ — $ (229 ) $ 1,452

Stockholders' equity (Tables)

Stockholders' equity (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016, 2015 and 2014. Common Stock Class A Class B Class C Class D Class E Class F Class G Total Shares issued at January 1, 2014 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 Restricted stock issuance — — — — — — — — Restricted stock repurchased (2,597 ) — — — — — — (2,597 ) Restricted stock forfeited (9,006 ) — — — — — — (9,006 ) Shares issued at December 31, 2016 333,686 344,859 209,882 — 504,276 1 2 1,392,706 (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, 2016
Commitments And Contingencies Disclosure [Abstract]
Unrecorded Unconditional Purchase Obligations Disclosure	Based on current prices, our estimated minimum purchase obligations under our CO 2 2017 $ 1,386 2018 1,690 2019 1,934 2020 1,934 2021 1,934 2022 and thereafter 2,665 $ 11,543
Schedule of Future Minimum Rental Payments for Operating Leases	As of December 31, 2016, total remaining payments associated with our operating leases were: 2017 $ 1,369 2018 1,367 2019 1,362 2020 1,330 2021 1,292 2022 and thereafter 479 $ 7,199

Oil and natural gas activities

Oil and natural gas activities (Tables)	12 Months Ended
	Dec. 31, 2016
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Abstract]
Costs Incurred in Oil and Natural Gas Producing Activities	Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31: 2016 2015 2014 Property acquisition costs Proved properties $ 390 $ 1,192 $ 3,496 Unproved properties 15,497 24,735 84,938 Total acquisition costs 15,887 25,927 88,434 Development costs 114,472 150,261 561,578 Exploration costs 19,055 33,091 90,146 Total $ 149,414 $ 209,279 $ 740,158
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: 2016 2015 2014 DD&A $ 111,793 $ 204,692 $ 231,761 DD&A per BOE: $ 12.52 $ 20.07 $ 21.10
Oil and Natural Gas Properties not Subject to Amortization	Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed. Year incurred 2016 2015 Total Leasehold acquisitions $ 14,170 $ 1,285 $ 15,455 Capitalized interest 1,356 538 1,894 Wells and facilities in progress of completion 3,004 — 3,004 Total unevaluated oil and natural gas properties excluded from amortization $ 18,530 $ 1,823 $ 20,353

Disclosures about oil and nat37

Disclosures about oil and natural gas activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 are as follows: Oil (MBbls) Natural gas (MMcf) Natural gas liquids (MBbls) Total (MBoe) Proved developed and undeveloped reserves As of January 1, 2014 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 Extensions and discoveries 4,037 18,085 1,499 8,550 Revisions (1) (16,312 ) (44,965 ) (57 ) (23,864 ) Production (4,870 ) (15,889 ) (1,408 ) (8,926 ) Balance at December 31, 2016 96,621 135,449 12,105 131,301 Proved developed reserves: January 1, 2014 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 December 31, 2016 28,590 108,800 9,352 56,076 Proved undeveloped reserves: January 1, 2014 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 December 31, 2016 68,031 26,649 2,753 75,225 (1) The downward revision in our reserves during 2016 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, revision in the base water flood decline curve at our North Burbank Unit, and the decline in SEC pricing. 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 were not expected to be developed within five-years and a decline in the estimated sales margin on 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, 2016 2015 2014 Future cash flows $ 4,635,481 $ 6,327,363 $ 11,275,090 Future production costs (1,998,001 ) (2,670,692 ) (3,605,107 ) Future development and abandonment costs (1,147,390 ) (1,536,063 ) (1,726,955 ) Future income tax provisions — (89,999 ) (1,487,121 ) Net future cash flows 1,490,090 2,030,609 4,455,907 Less effect of 10% discount factor (961,309 ) (1,345,920 ) (2,561,207 ) Standardized measure of discounted future net cash flows $ 528,781 $ 684,689 $ 1,894,700
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, 2016 2015 2014 Beginning of year $ 684,689 $ 1,894,700 $ 1,743,772 Sale of oil and natural gas produced, net of production costs (141,732 ) (196,319 ) (502,928 ) Net changes in prices and production costs (296,299 ) (2,230,601 ) 116,977 Extensions and discoveries 79,990 101,384 286,500 Improved recoveries — 524,436 148,673 Changes in future development costs 278,653 204,199 (91,027 ) Development costs incurred during the period that reduced future development costs 63,894 80,103 316,490 Revisions of previous quantity estimates (1) (223,218 ) (495,794 ) (40,481 ) Purchases and sales of reserves in place, net — (47,079 ) (278,825 ) Accretion of discount 68,545 237,134 223,324 Net change in income taxes 21,139 605,766 (46,584 ) Changes in production rates and other (6,880 ) 6,760 18,809 End of year $ 528,781 $ 684,689 $ 1,894,700 (1) Amounts in 2016 are primarily the result of removing proved undeveloped reserves that are not expected to be developed within the five years, a revision in the base water flood decline curve at our North Burbank Unit and the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. Amounts in 2015 are primarily the result of the decrease in SEC pricing, 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. 2016 2015 2014 Oil (per Bbl) $ 42.75 $ 50.28 $ 94.99 Natural gas (per Mcf) $ 2.49 $ 2.58 $ 4.35 Natural gas liquids (per Bbl) $ 13.47 $ 15.84 $ 36.10

Nature of operations and summ38

Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash and accounts receivable
Restricted cash	$ 1,400
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	$ 13,818	$ 14,149
Accrued commodity sales	31,304	21,645
Derivative settlements	119,303	40,380
Other	1,657	3,329
Allowance for doubtful accounts	(553)	(503)
Accounts receivable, net	46,226	$ 79,000
JP Morgan Chase Bank, N.A.
Cash and accounts receivable
Cash held	36,502
Cash | Arvest Bank
Cash and accounts receivable
Cash held	48,023
Cash Equivalents | Arvest Bank
Cash and accounts receivable
Cash held	$ 101,127

Nature of operations and summ39

Nature of operations and summary of significant accounting policies (Inventories) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Energy Related Inventory [Abstract]
Equipment inventory	$ 8,165	$ 11,470
Commodities	1,418	1,698
Inventory valuation allowance	(2,232)	(839)
Inventories, net	$ 7,351	$ 12,329

Nature of operations and summ40

Nature of operations and summary of significant accounting policies (Inventory Adjustments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Inventory Adjustments [Abstract]
Inventory - lower of cost or market adjustment	$ 1,393	$ 16,207	$ 0
Other Energy Equipment
Inventory Adjustments [Abstract]
Inventory - lower of cost or market adjustment	$ 1,393	$ 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, 2016
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 (Asset Impairment) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Oct. 31, 2016USD ($)Rig	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)Rig	Dec. 31, 2014USD ($)
Long Lived Assets Held For Sale [Line Items]
Loss on impairment of other assets		$ 1,393	$ 16,207	$ 0
Number of drilling rigs | Rig			4
Number of drilling rigs to be sold | Rig	4
Sale price of drilling rigs	$ 2,000
Sale of property closing period	2017-01
Upstream Equipment
Long Lived Assets Held For Sale [Line Items]
Loss on impairment of other assets			$ 6,015

Nature of operations and summ43

Nature of operations and summary of significant accounting policies (Income Taxes) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Income tax penalties and interest accrued	$ 0	$ 0
Uncertain tax positions	$ 0	$ 0

Nature of operations and summ44

Nature of operations and summary of significant accounting policies (Gas Balancing) (Details) $ in Thousands	Dec. 31, 2016USD ($)MMcf	Dec. 31, 2015USD ($)MMcf
Oil And Gas In Process Activities [Line Items]
Gas balancing payable | $	$ 1,405	$ 1,303
Under Production
Oil And Gas In Process Activities [Line Items]
Gas balancing volume (in MMcf)	0	0
Over Production
Oil And Gas In Process Activities [Line Items]
Gas balancing volume (in MMcf)	1,218	1,253

Nature of operations and summ45

Nature of operations and summary of significant accounting policies (Cost Reduction Initiatives) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives expense	$ 2,879	$ 10,028	$ 0
One-time Severance and Termination Benefits
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives expense	2,772	7,757
Professional Fees
Restructuring Cost and Reserve [Line Items]
Cost reduction initiatives expense	$ 107	$ 2,271

Nature of operations and summ46

Nature of operations and summary of significant accounting policies (Recently Adopted Accounting Pronouncements) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Unamortized debt issuance cost	[1]	$ 2,303	$ 23,426
Senior Notes
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Unamortized debt issuance cost			18,359
Existing Credit Facility
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Unamortized debt issuance cost		$ 2,303	$ 5,067
[1]	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below.

Chapter 11 Reorganization - Nar

Chapter 11 Reorganization - Narrative (Details)	Mar. 21, 2017USD ($)DirectorMember$ / sharesshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Chapter Eleven Reorganization [Line Item]
Senior Notes and associated accrued interest		$ 1,267,410,000
Accounts payable and accrued liabilities		9,212,000
Accrued payroll and benefits payable		4,048,000
Revenue distribution payable		3,474,000
Liabilities subject to compromise		1,284,144,000
Professional fees		15,484,000
Claims for non-performance of executory contract		1,236,000
Total reorganization items		$ 16,720,000	$ 0	$ 0
Subsequent Event | Midpoint [Member]
Chapter Eleven Reorganization [Line Item]
Reorganization plan, enterprise value of the post emergence	$ 1,200,000,000
Subsequent Event | Maximum
Chapter Eleven Reorganization [Line Item]
Fresh start voting share percentage of existing shareholders in emerging entity	50.00%
Reorganization plan, enterprise value of the post emergence	$ 1,350,000,000
Subsequent Event | Minimum
Chapter Eleven Reorganization [Line Item]
Reorganization plan, enterprise value of the post emergence	$ 1,050,000,000
Subsequent Event | New Common Stock
Chapter Eleven Reorganization [Line Item]
Common stock shares issued | shares	45,000,000
Plan of Reorganization | Subsequent Event
Chapter Eleven Reorganization [Line Item]
Senior Notes and associated accrued interest	$ 1,267,410,000
General unsecured claims	2,981,000
Professional fees	6,953,000
Segregated account for professional fees attributable to our advisors	$ 11,000,000
Number of directors | Director	7
Number of members | Member	6
Plan of Reorganization | Subsequent Event | Existing Credit Facility
Chapter Eleven Reorganization [Line Item]
Amount of repayments on existing credit facility	$ 444,440,000
Plan of Reorganization | Subsequent Event | New Revolver
Chapter Eleven Reorganization [Line Item]
New credit facility, opening balance	120,000,000
Plan of Reorganization | Subsequent Event | New Term Loan
Chapter Eleven Reorganization [Line Item]
New credit facility, opening balance	150,000,000
Plan of Reorganization | Subsequent Event | Backstop Parties
Chapter Eleven Reorganization [Line Item]
Gross proceeds from rights offering	$ 50,000,000
Plan of Reorganization | Subsequent Event | New Common Stock
Chapter Eleven Reorganization [Line Item]
Common stock shares issued | shares	45,000,000
Percentage of common stock outstanding on conversion of debt	90.00%
Plan of Reorganization | Subsequent Event | New Common Stock | Mr. Mark Fischer, Founder and Former Chief Executive Officer
Chapter Eleven Reorganization [Line Item]
Warrants issued for purchase of common stock | shares	140,023
Exercise price of warrants per share | $ / shares	$ 36.78
Warrants expiry date	Jun. 30, 2018
Plan of Reorganization | Subsequent Event | New Common Stock | Management Incentive Plan
Chapter Eleven Reorganization [Line Item]
Additional shares authorized for issuance	7.00%
Plan of Reorganization | Subsequent Event | New Common Stock | Backstop Parties
Chapter Eleven Reorganization [Line Item]
Percentage of rights issued on common stock outstanding	9.00%
Percentage of outstanding stock received as fee	1.00%
Chaparral Energy Inc and Subsidiaries
Chapter Eleven Reorganization [Line Item]
Date of bankruptcy petition filed		May 9, 2016
Place of bankruptcy petition filed		United States Bankruptcy Court for the District of Delaware
Reorganization plan confirmation date		Mar. 10, 2017
Reorganization plan effective date		Mar. 21, 2017

Supplemental disclosures to t48

Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net cash provided by operating activities included:
Cash payments for interest		$ 25,764	$ 116,379	$ 112,196
Interest capitalized		(2,139)	(9,670)	(13,491)
Cash payments for interest, net of amounts capitalized		23,625	106,709	98,705
Cash payments for income taxes		250	640	591
Cash payments for reorganization items		10,670
Non-cash financing activities included:
Repayment of Existing Credit Facility with proceeds from early termination of derivative contracts (See Note 6)	$ 103,560	103,560
Non-cash investing activities included:
Asset retirement obligation additions and revisions		22,282	4,000	7,461
Change in accrued oil and gas capital expenditures		$ (19,725)	$ (105,312)	$ 43,971

Acquisitions and divestitures (

Acquisitions and divestitures (2015 Divestitures) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
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
Long Lived Assets Held For Sale [Line Items]
Number Of Divestitures | Divestiture			4
Number Of Planned Divestitures | Divestiture			5
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

Property and Equipment--Compone

Property and Equipment--Components of Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Furniture and fixtures	$ 2,518	$ 2,518
Automobiles and trucks	9,793	10,689
Machinery and equipment	53,757	55,963
Office and computer equipment	20,817	19,993
Building and improvements	25,085	25,534
Property and equipment, excluding land, gross	111,970	114,697
Less accumulated depreciation and amortization	79,415	75,041
Property and equipment, excluding land, net	32,555	39,656
Land	8,792	9,306
Property and equipment - at cost, net	$ 41,347	$ 48,962

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Long-term debt [Abstract]
Existing Credit Facility		$ 444,440	$ 367,000
Real estate mortgage notes payable		9,595	10,182
Installment notes payable		434	1,799
Capital lease obligations		16,946	19,437
Unamortized issuance costs	[1]	(2,303)	(23,426)
Total debt, net		469,112	1,583,701
Less current portion		$ 469,112	1,583,701
9.875% Senior Notes due 2020
Long-term debt [Abstract]
Senior Notes			293,815
Unamortized issuance costs			(4,078)
8.25% Senior Notes due 2021
Long-term debt [Abstract]
Senior Notes			384,045
Unamortized issuance costs			(5,459)
7.625% Senior Notes due 2022
Long-term debt [Abstract]
Senior Notes			530,849
Unamortized issuance costs			$ (8,822)
[1]	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below.

Debt (Components of Debt) (Pare

Debt (Components of Debt) (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
9.875% Senior Notes due 2020
Long-term debt [Abstract]
Unamortized discount	$ 0	$ 4,185
7.625% Senior Notes due 2022
Long-term debt [Abstract]
Unamortized premium	$ 0	$ 4,939
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
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	5.00%

Debt (Unamortized Debt Issuance

Debt (Unamortized Debt Issuance Costs) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Unamortized debt issuance costs
Total unamortized debt issuance costs	[1]	$ 2,303	$ 23,426
9.875% Senior Notes due 2020
Unamortized debt issuance costs
Total unamortized debt issuance costs			4,078
8.25% Senior Notes due 2021
Unamortized debt issuance costs
Total unamortized debt issuance costs			5,459
7.625% Senior Notes due 2022
Unamortized debt issuance costs
Total unamortized debt issuance costs			8,822
Existing Credit Facility
Unamortized debt issuance costs
Total unamortized debt issuance costs		$ 2,303	$ 5,067
[1]	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below.

Debt (Pre-emergence Debt) (Deta

Debt (Pre-emergence Debt) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Senior Notes
Debt Instrument [Line Items]
Amortization of senior note debt issuance costs	$ 602	$ 1,921	$ 2,335

Debt (Initial Maturities of Deb

Debt (Initial Maturities of Debt and Capital Leases) (Details) $ in Thousands	Dec. 31, 2016USD ($)
Maturities Of Long Term Debt [Abstract]
2,017	$ 448,033
2,018	3,295
2,019	12,321
2,020	298,679
2,021	384,762
2022 and thereafter	532,280
Long-term debt and capital leases	$ 1,679,370

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Gain on extinguishment of debt			$ 0	$ 31,590	$ 0
Grace periods to pay interest to avoid event of default	30 days
Senior Notes
Debt Instrument [Line Items]
Net amortization of discount (premium)			32	945	$ (268)
Senior note repurchase amount		$ 42,045		42,045
Debt instrument cash paid for repurchase		$ 9,995
Gain on extinguishment of debt				$ 31,590
Interest expense			$ 65,225

Debt (Premiums, Discounts and D

Debt (Premiums, Discounts and Debt Issuance Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Non-cash expense for write-off of debt issuance costs on Senior Notes	$ 17,756
Non-cash expense for write-off of debt discount costs on Senior Notes	4,014
Non-cash gain for write-off of debt premium on Senior Notes	(4,800)
Total	$ 16,970	$ 0	$ 0

Debt (Existing Credit Facility)

Debt (Existing Credit Facility) (Details) - USD ($)	Mar. 21, 2017	Sep. 30, 2016	Dec. 31, 2016	Mar. 31, 2016
Line Of Credit Facility [Line Items]
Amount utilized to offset outstanding borrowings under credit facility		$ 103,560,000	$ 103,560,000
Existing Credit Facility
Line Of Credit Facility [Line Items]
Borrowing base amount				$ 550,000,000
Availability under the facility			0
Proceeds from additional borrowing credit facility			181,000,000
Amount utilized to offset outstanding borrowings under credit facility			$ 103,560,000
Weighted average interest rate			5.25%
Additional interest rate on outstanding amounts in event of default waived			2.00%
Existing Credit Facility | Subsequent Event
Line Of Credit Facility [Line Items]
Repayments of debt	$ 444,440,000

Debt (Schedule of Initial Outst

Debt (Schedule of Initial Outstanding Amounts Under New Credit Facility) (Details) - USD ($) $ in Thousands		Mar. 21, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
New Credit Facility			$ 444,440	$ 367,000
Unamortized issuance costs	[1]		$ (2,303)	$ (23,426)
Post Emergent | Subsequent Event
Debt Instrument [Line Items]
Total		$ 268,125
Post Emergent | Subsequent Event | New Term Loan
Debt Instrument [Line Items]
New Credit Facility	[2]	149,250
Post Emergent | Subsequent Event | New Revolver
Debt Instrument [Line Items]
New Credit Facility		120,000
Unamortized issuance costs	[2]	$ (1,125)
[1]	Debt issuance costs are presented as a direct deduction from debt rather than an asset pursuant to recent accounting guidance. See table below.
[2]	Upfront fees of 0.5% were paid to the lenders under the New Credit Facility. The amount paid in connection with the New Term Loan is reflected as a discount on the loan and will be amortized under the effective interest method. The amount paid in connection with the New Revolver will be reflected as a reduction to the liability whenever outstanding borrowings exceed the remaining unamortized issuance costs, otherwise such amount will be reflected as an asset. The issuance cost related to the New Revolver will be amortized ratably over the life of the facility.

Debt (Schedule of Initial Out61

Debt (Schedule of Initial Outstanding Amounts Under New Credit Facility) (Parenthetical) (Details) - Post Emergent - Subsequent Event $ in Thousands	Mar. 21, 2017USD ($)
New Term Loan
Debt Instrument [Line Items]
Unamortized discount	$ 750
New Credit Facility
Debt Instrument [Line Items]
Percentage of upfront fee	0.50%

Debt (New Term Loan) (Details)

Debt (New Term Loan) (Details) - Post Emergent - New Term Loan - Subsequent Event	Mar. 21, 2017
Line Of Credit Facility [Line Items]
Debt instrument maturity date	Mar. 21, 2021
Alternate Base Rate
Line Of Credit Facility [Line Items]
Basis spread on variable rate	6.75%
Adjusted LIBO Rate
Line Of Credit Facility [Line Items]
Basis spread on variable rate	7.75%
Debt instrument floor rate	1.00%

Debt (Schedule of Mandatory Pri

Debt (Schedule of Mandatory Principal Payment According to Schedule of Remaining Outstanding Balance Due upon Maturity) (Details) - Post Emergent - New Term Loan - Subsequent Event $ in Thousands	Mar. 21, 2017USD ($)
Debt Instrument [Line Items]
2,017	$ 1,183
2,018	1,500
2,019	3,750
2,020	6,750
Total mandatory prepayments	$ 13,183

Debt (New Revolver) (Details)

Debt (New Revolver) (Details) - Existing Credit Facility - USD ($)	Mar. 21, 2017	Dec. 31, 2016	Mar. 31, 2016
Line Of Credit Facility [Line Items]
Borrowing base amount			$ 550,000,000
Availability under the facility		$ 0
Post Emergent | New Revolver | Subsequent Event
Line Of Credit Facility [Line Items]
Borrowing base amount	$ 400,000,000
Debt instrument maturity date	Mar. 21, 2021
Initial borrowing base amount	$ 225,000,000
Debt instrument redetermination date	May 1, 2018
Availability under the facility	$ 104,172,000
Commitment fee on unused portion of the borrowing base	0.50%
Number of days to make election to eliminate borrowings in excess of borrowing base as the result of a redetermination	10 days
Post Emergent | New Revolver | Subsequent Event | 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	45 days
Post Emergent | New Revolver | Subsequent Event | 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	45 days
Equal monthly installment period to eliminate borrowings in excess of borrowing base as the result of redetermination	6 months
Post Emergent | New Revolver | Subsequent Event | Letter of Credit
Line Of Credit Facility [Line Items]
Basis spread on variable rate	0.125%
Post Emergent | New Revolver | Subsequent Event | Alternate Base Rate
Line Of Credit Facility [Line Items]
Additional interest rate on outstanding amounts in event of default	2.00%
Post Emergent | New Revolver | Subsequent Event | Alternate Base Rate | Minimum
Line Of Credit Facility [Line Items]
Basis spread on variable rate	2.00%
Post Emergent | New Revolver | Subsequent Event | Alternate Base Rate | Maximum
Line Of Credit Facility [Line Items]
Basis spread on variable rate	3.00%
Post Emergent | New Revolver | Subsequent Event | Adjusted LIBO Rate
Line Of Credit Facility [Line Items]
One month interest period	1 month
Two month interest period	2 months
Three month interest period	3 months
Six month interest period	6 months
Post Emergent | New Revolver | Subsequent Event | Adjusted LIBO Rate | Minimum
Line Of Credit Facility [Line Items]
Basis spread on variable rate	3.00%
Post Emergent | New Revolver | Subsequent Event | Adjusted LIBO Rate | Maximum
Line Of Credit Facility [Line Items]
Basis spread on variable rate	4.00%

Debt (Other Provisions) (Detail

Debt (Other Provisions) (Details) - Post Emergent - Subsequent Event - Existing Credit Facility	Mar. 21, 2017USD ($)qtr
Line Of Credit Facility [Line Items]
Interest payment description	In the case of Alternate Base Rate loans, interest is payable quarterly in arrears. In the case of Adjusted LIBO Rate borrowings, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period
Liquidity requirement	$ 100,000,000
Number of consecutive quarters | qtr	4
Minimum
Line Of Credit Facility [Line Items]
Liquidity requirement	$ 25,000,000
Current Ratio covenant	100.00%
Asset coverage ratio covenant	135.00%
Maximum
Line Of Credit Facility [Line Items]
Ratio of debt to EBITDAX	350.00%

Debt (Capital Leases) (Details)

Debt (Capital Leases) (Details) - U.S. Bank National Association - Capital Lease Obligations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2013
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

Derivative instruments - Summar

Derivative instruments - Summary of derivatives outstanding (Details) bbl in Thousands, MMBTU in Thousands	Jan. 31, 2017bblMMBTU$ / bbl$ / MMBTU	Dec. 31, 2016bblMMBTU$ / bbl$ / MMBTU
Swaps | Derivative Maturing in 2017 | Crude Oil Derivative Contracts
Derivative [Line Items]
Volume | bbl		3,631
Weighted average fixed price		54.97
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative Contracts
Derivative [Line Items]
Volume | MMBTU		9,575
Weighted average fixed price | $ / MMBTU		3.34
Swaps | Derivative Maturing in 2017 | Natural Gas Derivative Contracts | Subsequent Event
Derivative [Line Items]
Volume | MMBTU	154
Fixed price | $ / MMBTU	3.40
Swaps | Derivative Maturing in 2018 | Crude Oil Derivative Contracts
Derivative [Line Items]
Volume | bbl		2,116
Weighted average fixed price		54.92
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative Contracts
Derivative [Line Items]
Volume | MMBTU		5,861
Weighted average fixed price | $ / MMBTU		3.03
Swaps | Derivative Maturing in 2019 | Crude Oil Derivative Contracts
Derivative [Line Items]
Volume | bbl		1,204
Weighted average fixed price		54.25
Swaps | Derivative Maturing in 2019 | Crude Oil Derivative Contracts | Subsequent Event
Derivative [Line Items]
Volume | bbl	108
Fixed price	54.40
Swaps | Derivative Maturing in 2019 | Natural Gas Derivative Contracts
Derivative [Line Items]
Volume | MMBTU		3,322
Weighted average fixed price | $ / MMBTU		2.86
Collars | Derivative Maturing in 2018 | Crude Oil Derivative Contracts
Derivative [Line Items]
Volume | bbl		183
Weighted average fixed price per Bbl, purchased puts		50
Weighted average fixed price per Bbl, sold calls		60.50

Derivative instruments - Additi

Derivative instruments - Additional information (Details) $ in Thousands	Mar. 26, 2015USD ($)MMBTUMBbls	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	May 31, 2016MMBTUMBbls	Dec. 31, 2015USD ($)
Derivative [Line Items]
Receivable derivative settlements			$ 119,303		$ 40,380
Amount utilized to offset outstanding borrowings under credit facility		$ 103,560	$ 103,560
Early settlement | Crude Oil Derivative Contracts
Derivative [Line Items]
Volume | MBbls	495			3,400
Early settlement | Natural Gas Derivative Contracts
Derivative [Line Items]
Volume | MMBTU	12,280,000			28,800,000
Early settlement | Crude Oil and Natural Gas Derivative
Derivative [Line Items]
Settlement of non-hedge derivative instruments, net proceeds	$ 15,395

Derivative Instruments (Derivat

Derivative Instruments (Derivative instruments recorded on the balance sheet at fair value) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Fair value of derivative instruments
Derivative assets, gross		$ 184	$ 164,396
Derivative liabilities, gross		(13,553)	(1,158)
Derivative assets (liabilities), net		(13,369)	163,238
Netting adjustments	[1]	184	1,158
Derivative Liability, Netting adjustments	[1]	(184)	(1,158)
Current derivative assets, net		0	143,737
Current derivative liabilities, net		(7,525)	0
Current derivative assets (liabilities), net		(7,525)	143,737
Long-term derivative assets, net		0	19,501
Long-term derivative liabilities, net		(5,844)	0
Long-term derivative assets (liabilities), net		(5,844)	19,501
Natural Gas Derivative Contracts
Fair value of derivative instruments
Derivative assets, gross		184	41,328
Derivative liabilities, gross		(3,658)	(1,158)
Derivative assets (liabilities), net		(3,474)	40,170
Crude Oil Derivative Contracts
Fair value of derivative instruments
Derivative assets, gross			123,068
Derivative liabilities, gross		(9,895)
Derivative assets (liabilities), net		$ (9,895)	$ 123,068
[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 related to the same current versus noncurrent classification on the balance sheet.

Derivative Instruments (Non-hed

Derivative Instruments (Non-hedge derivative gains (losses) in the consolidated statements of operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Change in fair value of commodity price derivatives	$ (176,607)	$ (88,317)	$ 228,903
Settlement gains on commodity price derivatives	62,626	218,210	2,417
Settlement gains on early terminations of commodity price derivatives	91,144	15,395
Non-hedge derivative (losses) gains	$ (22,837)	$ 145,288	$ 231,320

Fair value measurements (Recurr

Fair value measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross		$ 184	$ 164,396
Derivative liabilities, gross		(13,553)	(1,158)
Derivative assets (liabilities), net		(13,369)	163,238
Derivative assets, amount offset		(184)	(1,158)
Derivative liabilities, amounts offset		184	1,158
Derivative assets, net			163,238
Derivative liabilities, net		(13,369)	0
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net		(13,369)	163,238
Derivative assets, amount offset	[1]	(184)	(1,158)
Derivative liabilities, amounts offset	[1]	184	1,158
Derivative assets amount offset (liabilities), net	[1]	0	0
Derivative assets, net		0	163,238
Derivative liabilities, net		(13,369)	0
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		184	41,328
Derivative liabilities, gross		(13,455)	(1,158)
Derivative assets (liabilities), net		(13,271)	40,170
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		0	123,068
Derivative liabilities, gross		(98)	0
Derivative assets (liabilities), net		$ (98)	$ 123,068
[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, 2016	Dec. 31, 2015
Level 3 Rollforward
Beginning balance	$ 123,068	$ 195,167
Realized and unrealized (losses) gains included in non-hedge derivative (losses) gains	(9,314)	105,055
Purchases	0	0
Settlements received	(113,852)	(177,154)
Ending balance	(98)	123,068
(Losses) gains relating to instruments still held at the reporting date included in non- hedge derivative (losses) gains for the period	$ (98)	$ 61,260

Fair value measurements (Nonrec

Fair value measurements (Nonrecurring Fair Value Measurements) (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 31, 2017Rig	Oct. 31, 2016Rig
Nonrecurring Fair Value Measurements
Loss on impairment of other assets | $		$ 1,393	$ 16,207	$ 0
Number of drilling rigs to be sold | Rig						4
Significant Unobservable Inputs (Level 3) | Nonrecurring Fair Value Measurements
Nonrecurring Fair Value Measurements
Annual inflation rate		2.42%	2.91%
Credit-adjusted risk-free interest rate		17.05%	15.09%
Loss on impairment of other assets | $	$ 6,015	$ 0		$ 0
Significant Unobservable Inputs (Level 3) | Nonrecurring Fair Value Measurements | Subsequent Event
Nonrecurring Fair Value Measurements
Number of drilling rigs to be sold | Rig					4

Fair value measurements (Fair V

Fair value measurements (Fair Value of Other Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value of Other Financial Instruments
Existing Credit Facility	$ 444,440	$ 367,000
Significant Other Observable Inputs (Level 2) | Carrying Value
Fair Value of Other Financial Instruments
Existing Credit Facility		367,000
Long-term debt	1,217,984	1,587,690
Significant Other Observable Inputs (Level 2) | Estimated Fair Value
Fair Value of Other Financial Instruments
Existing Credit Facility		367,000
Long-term debt	1,093,598	672,165
Significant Other Observable Inputs (Level 2) | 9.875% Senior Notes due 2020 | Carrying Value
Fair Value of Other Financial Instruments
Senior Notes	298,000	293,815
Significant Other Observable Inputs (Level 2) | 9.875% Senior Notes due 2020 | Estimated Fair Value
Fair Value of Other Financial Instruments
Senior Notes	268,200	75,750
Significant Other Observable Inputs (Level 2) | 8.25% Senior Notes due 2021 | Carrying Value
Fair Value of Other Financial Instruments
Senior Notes	384,045	384,045
Significant Other Observable Inputs (Level 2) | 8.25% Senior Notes due 2021 | Estimated Fair Value
Fair Value of Other Financial Instruments
Senior Notes	344,680	96,956
Significant Other Observable Inputs (Level 2) | 7.625% Senior Notes due 2022 | Carrying Value
Fair Value of Other Financial Instruments
Senior Notes	525,910	530,849
Significant Other Observable Inputs (Level 2) | 7.625% Senior Notes due 2022 | Estimated Fair Value
Fair Value of Other Financial Instruments
Senior Notes	470,689	120,478
Significant Other Observable Inputs (Level 2) | Secured Debt | Carrying Value
Fair Value of Other Financial Instruments
Other secured debt	10,029	11,981
Significant Other Observable Inputs (Level 2) | Secured Debt | Estimated Fair Value
Fair Value of Other Financial Instruments
Other secured debt	$ 10,029	$ 11,981

Fair value measurements (Counte

Fair value measurements (Counterparty Credit Risk) (Details) $ in Thousands	Dec. 31, 2016USD ($)financial_institutions
Counterparty Credit Risk
Derivative liabilities subject to acceleration | $	$ 13,553
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	4
Derivative contracts, number of counterparties subject to offset under existing credit facility	4

Fair value measurements (Deriva

Fair value measurements (Derivatives Offset in the Consolidated Balance Sheets) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Derivative assets, gross		$ 184	$ 164,396
Derivative assets, amount offset		(184)	(1,158)
Derivative assets			163,238
Derivative assets, not offset	[1]	0	0
Existing credit facility balance available to offset net derivative assets		0	(103,618)
Derivative asset, net			59,620
Derivative liabilities, gross		(13,553)	(1,158)
Derivative liabilities, amounts offset		184	1,158
Derivative liabilities		(13,369)	0
Derivative liabilities, not offset	[1]	0	0
Existing credit facility balance available to offset net derivative liabilities		0	0
Derivative liability, net		(13,369)	0
Derivative Asset (Liability), Fair Value, Gross Asset		(13,369)	163,238
Derivative Asset (Liability), Fair Value, Gross Liability		0	0
Derivative Asset (Liability), Net		(13,369)	163,238
Derivative liability asset not offset	[1]	0	0
Derivative asset (liability), net		$ (13,369)	$ 59,620
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Valero Energy Corporation
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	15.60%	20.70%	23.70%
Coffeyville Resources LLC
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	19.30%	14.50%	14.00%
Phillips 66 Company
Concentration Risk [Line Items]
Percentage of sales to significant purchaser	15.10%	11.80%

Asset retirement obligations (D

Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 48,612	$ 47,424
Liabilities incurred in current period	3,918	1,861
Liabilities settled or disposed in current period	(2,729)	(6,472)
Revisions in estimated cash flows	18,364	2,139
Accretion expense	3,972	3,660
Ending balance	72,137	48,612
Less current portion included in accounts payable and accrued liabilities	6,681	2,178
Asset retirement obligations, long-term	65,456	46,434
Cash in escrow	$ 1,519	$ 1,567

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Current income taxes
Federal	$ (10)	$ (21)	$ (22)
State	(92)	195	574
Total current income taxes	(102)	174	552
Deferred income taxes
Federal	0	(161,879)	115,699
State	0	(15,514)	8,192
Total deferred income taxes	0	(177,393)	123,891
Income tax (benefit) expense	$ (102)	$ (177,219)	$ 124,443

Income Taxes--Rate Reconciliati

Income Taxes--Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State income taxes, net of federal benefit	4.10%	3.10%	2.60%
Statutory depletion	(0.00%)	(0.00%)	(0.20%)
Valuation allowance	(39.00%)	(26.50%)	0.00%
Other, net	(0.10%)	0.10%	(0.10%)
Effective tax rate	0.00%	11.70%	37.30%

Income Taxes--Components of Def

Income Taxes--Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Asset retirement obligations	$ 15,825	$ 14,669
Accrued expenses, allowance and other	31,711	11,564
Property and equipment	241,126	259,096
Inventories	0	372
Derivative instruments	7,048	0
Net operating loss carryforwards - Federal	241,109	154,265
Net operating loss carryforwards - State	33,605	21,466
Statutory depletion carryforwards	4,158	3,962
Alternative minimum tax credit carryforwards	308	308
Deferred tax assets, gross	574,890	465,702
Less valuation allowance	(574,338)	(411,147)	$ (411,147)
Deferred tax asset	552	54,555
Derivative instruments	0	(54,555)
Inventories	(552)	0
Deferred tax liability	(552)	(54,555)
Net deferred tax liability	$ 0	$ 0

Income Taxes--Narrative (Detail

Income Taxes--Narrative (Details) - USD ($) $ in Thousands	Mar. 21, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Income Tax Disclosure [Line Items]
Estimated valuation allowance		$ 574,338	$ 411,147	$ 411,147
Discrete item associated with Federal and State NOL carryforwards				$ 126,000
Valuation allowance, Deferred tax asset, Increase (Decrease)		$ 163,191
Purchase or sale of stock percentage		5.00%
Offering stock period		3 years
Possible ownership change, evaluation period		2 years
Senior Notes and associated accrued interest		$ 1,267,410
Subsequent Event
Income Tax Disclosure [Line Items]
Cancellation of indebtedness income, realized	$ 0
Plan of Reorganization | Subsequent Event
Income Tax Disclosure [Line Items]
Senior Notes and associated accrued interest	1,267,410
General unsecured claims	$ 2,981
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		$ 844,000
Internal Revenue Service (IRS)
Income Tax Disclosure [Line Items]
Operating loss carryforwards		689,000
Operating loss carryforwards, not subject to expiration		$ 12,000

Deferred compensation (Phantom

Deferred compensation (Phantom Stock Plan and Restricted Stock Unit Plan) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Phantom Shares
Shares
Granted (in shares)	0
Restricted Stock Units (RSU)
Shares
Granted (in shares)	0
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
Shares
Granted (in shares)	0	0	0
Unvested and outstanding at beginning of period (in shares)	10,619	23,179	53,162
Vested (in shares)	(9,729)	(6,456)	(22,041)
Forfeited (in shares)	(890)	(6,104)	(7,942)
Unvested and outstanding at end of period (in shares)	0	10,619	23,179
Weighted average grant date fair value
Unvested and outstanding at beginning of period ($ per share)	$ 18.62	$ 20.18	$ 17.01
Granted ($ per share)	0	0	0
Vested ($ per share)	18.39	24.48	12.61
Forfeited ($ per share)	$ 21.09	18.33	19.95
Unvested and outstanding at end of period ($ per share)		$ 18.62	$ 20.18
Vest date fair value
Vest date fair value		$ 25	$ 212
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
Shares
Granted (in shares)	0	59,571	504,752
Unvested and outstanding at beginning of period (in shares)	269,886	569,160	325,297
Vested (in shares)	(140,818)	(216,941)	(118,400)
Forfeited (in shares)	(30,472)	(141,904)	(142,489)
Unvested and outstanding at end of period (in shares)	98,596	269,886	569,160
Weighted average grant date fair value
Unvested and outstanding at beginning of period ($ per share)	$ 10.53	$ 9.91	$ 13.53
Granted ($ per share)	0	14.88	8.52
Vested ($ per share)	9.01	10.73	13.96
Forfeited ($ per share)	8.23	9.56	9.85
Unvested and outstanding at end of period ($ per share)	$ 7.18	$ 10.53	$ 9.91
Vest date fair value
Vest date fair value		$ 855	$ 1,094
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

Deferred compensation (Cash Inc

Deferred compensation (Cash Incentive Plan) (Details) - The 2015 Cash LTIP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Deferred Compensation Arrangement With Individual Excluding Share Based Payments And Postretirement Benefits [Line Items]
Deferred Compensation Arrangement with Individual, Requisite Service Period	4 years
Amount awarded		$ 3,297
Expense	$ 1,008	$ 610
Payments	$ 666

Deferred compensation (2010 Equ

Deferred compensation (2010 Equity Incentive Plan) (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 01, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shares
Restricted stock		2,597	5,725	2,025
Vest date fair value
Aggregate intrinsic value of unvested Time Vested restricted shares outstanding		$ 0
Common Class A
Shares
Restricted stock		2,597	5,725	2,025
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)		$ 795.13	$ 791.52	$ 634.67
Granted ($ per share)			533.80	818.50
Vested ($ per share)		798.85	775.17	643.55
Forfeited ($ per share)		799.30	774.21	631.54
Modified ($ per share)				969
Unvested and outstanding at end of period ($ per share)		$ 790.91	$ 795.13	$ 791.52	$ 634.67
Shares
Unvested and outstanding at beginning of period (in shares)		13,979	25,834	19,246
Granted (in shares)		0	610	5,245
Vested (in shares)		(5,279)	(8,468)	(4,951)
Forfeited (in shares)		(2,033)	(3,997)	(3,045)
Modified (in shares)				9,339
Unvested and outstanding at end of period (in shares)		6,667	13,979	25,834	19,246
Restricted stock		2,597	5,725	2,025
Estimated fair value per share at end of period ($ per share)		$ 0
Vest date fair value
Vest date fair value		$ 93	$ 4,497	$ 4,118
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)		$ 278.97	$ 292.92	$ 307.45
Granted ($ per share)			113.90	204.90
Vested ($ per share)		0	0
Forfeited ($ per share)		283.99	323.53	264.54
Modified ($ per share)				296.69
Unvested and outstanding at end of period ($ per share)		$ 277.33	$ 278.97	$ 292.92	$ 307.45
Shares
Unvested and outstanding at beginning of period (in shares)		28,448	38,943	46,701
Granted (in shares)		0	599	10,033
Vested (in shares)		0	0	0
Forfeited (in shares)		(6,973)	(11,094)	(8,452)
Modified (in shares)				(9,339)
Unvested and outstanding at end of period (in shares)		21,475	28,448	38,943	46,701

Deferred compensation--Variable

Deferred compensation--Variables and Assumptions Used to Value Restricted Stock Awards (Details) - 2010 Equity Incentive Plan - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Service Vesting Conditions | Common Class A | Restricted Stock
Stock-Based Compensation [Line Items]
Discount for lack of marketability	25.00%	20.00%
Fair value per share of awards			$ 0
Service Vesting Conditions | Common Class A | Time And Performance Awards
Stock-Based Compensation [Line Items]
Fair value per share of awards			$ 0
Performance Vested | Restricted Stock
Stock-Based Compensation [Line Items]
Risk free interest rate, minimum	0.71%	0.25%
Risk free interest rate, maximum	1.44%	1.48%
Expected volatility, minimum	71.00%	52.00%
Expected volatility, maximum	81.00%	56.00%
Expected life	3 years	4 years
Expected dividends	$ 0	$ 0

Deferred compensation (Stock-ba

Deferred compensation (Stock-based compensation cost) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock-Based Compensation Expense [Abstract]
Stock-based compensation cost		$ (6,196)	$ (2,169)	$ 6,235
Less: stock-based compensation cost capitalized		958	229	(2,346)
Stock-based compensation (credit) expense		(5,238)	(1,940)	3,889
Recognized tax (expense) benefit associated with stock-based compensation			(229)	1,452
Payments for stock-based compensation		49	3,991	$ 2,995
Stock-based compensation costs included in accrued payroll and benefits payable		0	$ 81
Remaining unrecognized compensation cost		$ 207
Vest date fair value
Aggregate compensation cost	$ (5,985)

Stockholders' equity (Details)

Stockholders' equity (Details)		Mar. 21, 2017shares	Jan. 13, 2014shares	Dec. 31, 2014shares	Dec. 31, 2016$ / shares	Dec. 31, 2015$ / shares	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
Subsequent Event | Common Stock
Equity [Line Items]
Common stock shares issued or reserved for issuance		45,000,000
Class G Common Stock
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)
Class G Common Stock | 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 | Subsequent Event
Equity [Line Items]
Common stock shares issued or reserved for issuance		37,125,000
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
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)
Common Class B | Subsequent Event
Equity [Line Items]
Common stock shares issued or reserved for issuance		7,875,000
[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, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity [Line Items]
Balance at beginning of period (in shares)		1,404,309	1,423,916	1,422,160
Restricted stock issuance			1,209	15,278
Restricted stock repurchased		(2,597)	(5,725)	(2,025)
Restricted stock forfeited		(9,006)	(15,091)	(11,497)
Balance at end of period (in shares)		1,392,706	1,404,309	1,423,916
Common Class A
Equity [Line Items]
Balance at beginning of period (in shares)		345,289	364,896	70,117
Stock transfers	[1]			293,023
Restricted stock issuance			1,209	15,278
Restricted stock repurchased		(2,597)	(5,725)	(2,025)
Restricted stock forfeited		(9,006)	(15,091)	(11,497)
Balance at end of period (in shares)		333,686	345,289	364,896
Class B Common Stock
Equity [Line Items]
Balance at beginning of period (in shares)		344,859	344,859	357,882
Stock transfers	[1]			(13,023)
Balance at end of period (in shares)		344,859	344,859	344,859
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
Stock transfers	[1]			(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	2	3
Stock transfers	[1]			(1)
Balance at end of period (in shares)		2	2	2
[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, 2016USD ($)Person	Dec. 31, 2015USD ($)Person	Dec. 31, 2014USD ($)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	315	395	625
Contribution expense | $	$ 1,781	$ 2,363	$ 3,592

Commitments and Contingencies -

Commitments and Contingencies - Additional information (Details) $ in Thousands	Jan. 17, 2017	May 31, 2016	Jun. 30, 2014Lease	Dec. 31, 2016USD ($)contractsupplierMMcf	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Interest paid				$ 25,764	$ 116,379	$ 112,196
Leases, Operating [Abstract]
Rent expense				$ 6,693	8,753	11,088
Maximum remaining term of operating leases				5 years
Other commitments				$ 14,211
Naylor Farms Case | Subsequent Event
Loss Contingency, Information about Litigation Matters [Abstract]
Minimum percentage of plaintiff in modified class	60.00%
CO2 Compressor [Member]
Leases, Operating [Abstract]
Number Of Operating Leases | Lease			2
Operating lease expire, year		2,023	2,021
Minimum | Naylor Farms Case | Pending Litigation
Loss Contingency, Information about Litigation Matters [Abstract]
Damages sought				5,000
Minimum | Naylor Farms Case Putative Class Action | Pending Litigation
Loss Contingency, Information about Litigation Matters [Abstract]
Damages sought				150,000
Minimum | West Case Putative Class Action | Pending Litigation
Loss Contingency, Information about Litigation Matters [Abstract]
Damages sought				$ 75,000
C O 2 Purchase Contract
Loss Contingencies [Line Items]
Number of short-term interim agreements | contract				3
Number of suppliers | supplier				3
Number of short-term interim agreements | contract				1
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				43
Purchases under CO2 contracts				$ 2,289	3,000	4,890
C O 2 Purchase Contract | Minimum
Loss Contingencies [Line Items]
Average volume purchased (MMcf/d) | MMcf				42
Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding				$ 828	828
Interest paid				0	0	0
Proceeds from Letters				$ 0	$ 0	$ 0

Commitments and Contingencies92

Commitments and Contingencies - Minimum Purchase Obligations (Details) - C O 2 Purchase Contract $ in Thousands	Dec. 31, 2016USD ($)
Long-term Purchase Commitment [Line Items]
2,017	$ 1,386
2,018	1,690
2,019	1,934
2,020	1,934
2,021	1,934
2022 and thereafter	2,665
Total estimated minimum purchase obligations under CO2 contracts	$ 11,543

Commitments and Contingencies93

Commitments and Contingencies - Operating Lease Schedule (Details) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,017	$ 1,369
2,018	1,367
2,019	1,362
2,020	1,330
2,021	1,292
2022 and thereafter	479
Total	$ 7,199

Oil and Natural Gas Activities-

Oil and Natural Gas Activities--Costs Incurred (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property acquisition costs
Proved properties	$ 390	$ 1,192	$ 3,496
Unproved properties	15,497	24,735	84,938
Total acquisition costs	15,887	25,927	88,434
Development costs	114,472	150,261	561,578
Exploration costs	19,055	33,091	90,146
Total	$ 149,414	$ 209,279	$ 740,158

Oil and Natural Gas Activitie95

Oil and Natural Gas Activities--Depreciation, Depletion and Amortization Expense of Oil and Natural Gas Properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / Boe	Dec. 31, 2015USD ($)$ / Boe	Dec. 31, 2014USD ($)$ / Boe
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Abstract]
DD&A | $	$ 111,793	$ 204,692	$ 231,761
DD&A per BOE: | $ / Boe	12.52	20.07	21.10

Oil and Natural Gas Activitie96

Oil and Natural Gas Activities--Oil and Natural Gas Properties not Subject to Amortization (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Leasehold acquisitions	$ 15,455
Capitalized interest	1,894
Wells and facilities in progress of completion	3,004
Total unevaluated oil and natural gas properties excluded from amortization	20,353
2,016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Leasehold acquisitions	14,170
Capitalized interest	1,356
Wells and facilities in progress of completion	3,004
Total unevaluated oil and natural gas properties excluded from amortization	18,530
2,015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Leasehold acquisitions	1,285
Capitalized interest	538
Total unevaluated oil and natural gas properties excluded from amortization	$ 1,823

Oil and Natural Gas Activitie97

Oil and Natural Gas Activities--Narrative (Details)	12 Months Ended
	Dec. 31, 2016
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 Nat98

Disclosures about Oil and Natural Gas Activities (Unaudited)--Summary of Changes in Quantities of Proved Reserves (Details)		12 Months Ended
		Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcfMBbls		Dec. 31, 2014MBoeMMcfMBbls	Jan. 01, 2014MBoeMMcfMBbls
Reserve Quantities [Line Items]
Balance at beginning of period | MBoe		155,541	159,393		158,475
Purchase of minerals in place | MBoe			271		474
Sales of minerals in place | MBoe			(2,951)		(23,761)
Extensions and discoveries | MBoe		8,550	7,040		25,541
Revisions | MBoe	[1]	(23,864)	(34,426)		(3,608)
Improved recoveries | MBoe			36,414	[2]	13,254
Production | MBoe		(8,926)	(10,200)		(10,982)
Balance at end of period | MBoe		131,301	155,541		159,393
Proved developed reserves | MBoe		56,076	71,524		93,027	100,664
Proved undeveloped reserves | MBoe		75,225	84,017		66,366	57,811
Oil [Member]
Reserve Quantities [Line Items]
Balance at beginning of period		113,766	101,247		92,813
Purchase of minerals in place			38		276
Sales of minerals in place			(2,225)		(8,539)
Extensions and discoveries		4,037	3,651		12,776
Revisions	[1]	(16,312)	(19,840)		(3,356)
Improved recoveries			36,414	[2]	13,254
Production		(4,870)	(5,519)		(5,977)
Balance at end of period		96,621	113,766		101,247
Proved developed reserves		28,590	40,300		54,862	56,360
Proved undeveloped reserves		68,031	73,466		46,385	36,453
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance at beginning of period | MMcf		178,218	247,756		302,922
Purchase of minerals in place | MMcf			1,120		859
Sales of minerals in place | MMcf			(3,656)		(79,579)
Extensions and discoveries | MMcf		18,085	13,759		56,159
Revisions | MMcf	[1]	(44,965)	(61,973)		(11,957)
Improved recoveries | MMcf			0	[2]	0
Production | MMcf		(15,889)	(18,788)		(20,648)
Balance at end of period | MMcf		135,449	178,218		247,756
Proved developed reserves | MMcf		108,800	132,323		158,265	196,920
Proved undeveloped reserves | MMcf		26,649	45,895		89,491	106,002
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance at beginning of period		12,071	16,853		15,175
Purchase of minerals in place			46		55
Sales of minerals in place			(117)		(1,959)
Extensions and discoveries		1,499	1,096		3,405
Revisions	[1]	(57)	(4,257)		1,741
Improved recoveries			0	[2]	0
Production		(1,408)	(1,550)		(1,564)
Balance at end of period		12,105	12,071		16,853
Proved developed reserves		9,352	9,169		11,787	11,484
Proved undeveloped reserves		2,753	2,902		5,066	3,691
[1]	The downward revision in our reserves during 2016 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, revision in the base water flood decline curve at our North Burbank Unit, and the decline in SEC pricing. 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 were not expected to be developed within five-years and a decline in the estimated sales margin on 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 Nat99

Disclosures about Oil and Natural Gas Activities (Unaudited)--Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves Standardized Measure [Abstract]
Future cash flows	$ 4,635,481	$ 6,327,363	$ 11,275,090
Future production costs	(1,998,001)	(2,670,692)	(3,605,107)
Future development and abandonment costs	(1,147,390)	(1,536,063)	(1,726,955)
Future income tax provisions	0	(89,999)	(1,487,121)
Net future cash flows	1,490,090	2,030,609	4,455,907
Less effect of 10% discount factor	(961,309)	(1,345,920)	(2,561,207)
Standardized measure of discounted future net cash flows	$ 528,781	$ 684,689	$ 1,894,700	$ 1,743,772

Disclosures about Oil and Na100

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Principal Sources Of Change In Standardized Measure Of Discounted Future Net Cash Flow Relating To Proved Oil And Gas Reserves [Abstract]
Beginning of year		$ 684,689	$ 1,894,700	$ 1,743,772
Sale of oil and natural gas produced, net of production costs		(141,732)	(196,319)	(502,928)
Net changes in prices and production costs		(296,299)	(2,230,601)	116,977
Extensions and discoveries		79,990	101,384	286,500
Improved recoveries		0	524,436	148,673
Changes in future development costs		278,653	204,199	(91,027)
Development costs incurred during the period that reduced future development costs		63,894	80,103	316,490
Revisions of previous quantity estimates	[1]	(223,218)	(495,794)	(40,481)
Purchases and sales of reserves in place, net		0	(47,079)	(278,825)
Accretion of discount		68,545	237,134	223,324
Net change in income taxes		21,139	605,766	(46,584)
Changes in production rates and other		(6,880)	6,760	18,809
End of year		$ 528,781	$ 684,689	$ 1,894,700
[1]	Amounts in 2016 are primarily the result of removing proved undeveloped reserves that are not expected to be developed within the five years, a revision in the base water flood decline curve at our North Burbank Unit and the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. Amounts in 2015 are primarily the result of the decrease in SEC pricing, lower margins on existing reserves and a decrease in taxes as a result of the lower margins.

Disclosures about Oil and Na101

Disclosures about Oil and Natural Gas Activities (Unaudited)--Prices Used in Determining Future Net Revenues (Details)	12 Months Ended
	Dec. 31, 2016$ / bbl$ / Mcf	Dec. 31, 2015$ / bbl$ / Mcf	Dec. 31, 2014$ / 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	42.75	50.28	94.99
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	2.49	2.58	4.35
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	13.47	15.84	36.10