Chaparral Energy (CHAP) 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 06, 2019
Document And Entity Information [Abstract]
Entity Registrant Name	Chaparral Energy, Inc.
Entity Central Index Key	0001346980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Trading Symbol	CHAP
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		46,341,222

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 11,118	$ 37,446
Accounts receivable, net	62,652	66,087
Inventories, net	3,923	4,059
Prepaid expenses	2,593	2,814
Derivative instruments	0	24,025
Total current assets	80,286	134,431
Property and equipment, net	42,558	43,096
Right of use assets from operating leases	12,064	0
Oil and natural gas properties, using the full cost method:
Proved	976,025	915,333
Unevaluated (excluded from the amortization base)	484,021	466,616
Accumulated depreciation, depletion, amortization and impairment	(292,679)	(221,431)
Total oil and natural gas properties	1,167,367	1,160,518
Derivative instruments	0	2,199
Other assets	389	425
Total assets	1,302,664	1,340,669
Current liabilities:
Accounts payable and accrued liabilities	97,404	73,779
Accrued payroll and benefits payable	6,420	10,976
Accrued interest payable	5,934	13,359
Revenue distribution payable	20,714	26,225
Long-term debt and financing leases, classified as current	11,854	12,371
Derivative instruments	10,874	0
Total current liabilities	153,200	136,710
Long-term debt and financing leases, less current maturities	326,198	295,100
Derivative instruments	15,976	1,542
Noncurrent operating lease obligations	2,307	0
Deferred compensation	628	540
Asset retirement obligations	22,248	22,090
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized, none issued and outstanding	0	0
Common stock, $0.01 par value, 192,130,071 shares authorized; 46,648,581 issued and 46,307,056 outstanding at March 31, 2019 and 46,651,616 issued and 46,390,513 outstanding at December 31, 2018	467	467
Additional paid in capital	976,039	974,616
Treasury stock, at cost, 341,525 and 261,103 shares as of March 31, 2019 and December 31, 2018	(5,399)	(4,936)
Accumulated deficit	(189,000)	(85,460)
Accumulated deficit	782,107	884,687
Total liabilities and stockholders' equity	$ 1,302,664	$ 1,340,669

Consolidated Balance Sheets (_2

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	192,130,071	192,130,071
Common stock, shares issued	46,648,581	46,651,616
Common stock, shares outstanding	46,307,056	46,390,513
Treasury stock, shares	341,525	261,103

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($)		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Revenues:
Net commodity sales		$ 48,619,000	$ 57,889,000
Sublease revenue		1,198,000	1,198,000
Total revenues		49,817,000	59,087,000
Costs and expenses:
Lease operating		12,294,000	14,543,000
Production taxes		2,880,000	2,677,000
Depreciation, depletion and amortization		23,715,000	21,106,000
Impairment of oil and gas assets		49,722,000	0
General and administrative		8,313,000	11,507,000
Other		403,000	828,000
Total costs and expenses		97,327,000	50,661,000
Operating (loss) income		(47,510,000)	8,426,000
Non-operating income (expense):
Interest expense		(4,564,000)	(1,371,000)
Derivative losses		(51,016,000)	(16,501,000)
Loss on sale of assets		(1,000)	(1,044,000)
Other income, net		14,000	85,000
Net non-operating expense		(55,567,000)	(18,831,000)
Reorganization items, net		(463,000)	(1,037,000)
Loss before income taxes		(103,540,000)	(11,442,000)
Income tax expense		0	0
Net loss		$ (103,540,000)	$ (11,442,000)
Earnings per share:
Basic for Class A and Class B (in dollars per share)	[1]	$ (2.28)	$ (0.25)
Diluted for Class A and Class B (in dollars per share)	[1]	$ (2.28)	$ (0.25)
Weighted average shares used to compute earnings per share:
Basic for Class A and Class B (in shares)	[1]	45,456,214	45,143,297
Diluted for Class A and Class B (in shares)	[1]	45,456,214	45,143,297
[1]	See “Note 2—Earnings per share.”

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands	Total	Common stock	Additional paid in capital	Treasury stock	Accumulated deficit
Balance at beginning of period (in shares) at Dec. 31, 2017		46,827,762
Balance at beginning of the period at Dec. 31, 2017	$ 842,766	$ 468	$ 961,200	$ 0	$ (118,902)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation	5,581		5,581
Restricted stock forfeited (in shares)		(83,770)
Restricted stock forfeited	$ (1)	$ (1)
Repurchase of common stock (in shares)	0	(63,919)
Repurchase of common stock	$ (1,422)			(1,422)
Net loss	(11,442)				(11,442)
Balance at end of period (in shares) at Mar. 31, 2018		46,680,073
Balance at end of the period at Mar. 31, 2018	$ 835,482	$ 467	966,781	(1,422)	(130,344)
Balance at beginning of period (in shares) at Dec. 31, 2018	46,390,513	46,390,513
Balance at beginning of the period at Dec. 31, 2018	$ 884,687	$ 467	974,616	(4,936)	(85,460)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)		94,078
Stock-based compensation	1,424	$ 1	1,423
Restricted stock forfeited (in shares)		(97,113)
Restricted stock forfeited	$ (1)	$ (1)
Repurchase of common stock (in shares)	(80,422)	(80,422)
Repurchase of common stock	$ (463)			(463)
Net loss	$ (103,540)				(103,540)
Balance at end of period (in shares) at Mar. 31, 2019	46,307,056	46,307,056
Balance at end of the period at Mar. 31, 2019	$ 782,107	$ 467	$ 976,039	$ (5,399)	$ (189,000)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flows from operating activities
Net loss	$ (103,540,000)	$ (11,442,000)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	23,715,000	21,106,000
Derivative losses	51,016,000	16,501,000
Impairment of oil and gas assets	49,722,000	0
Loss on sale of assets	1,000	1,044,000
Other	542,000	1,630,000
Change in assets and liabilities
Accounts receivable	7,910,000	(12,140,000)
Inventories	207,000	(3,168,000)
Prepaid expenses and other assets	256,000	(179,000)
Accounts payable and accrued liabilities	(16,689,000)	(9,828,000)
Revenue distribution payable	(5,511,000)	2,151,000
Deferred compensation	925,000	4,701,000
Net cash provided by operating activities	8,554,000	10,376,000
Cash flows from investing activities
Expenditures for property, plant, and equipment and oil and natural gas properties	(64,044,000)	(99,941,000)
Proceeds from asset dispositions	0	73,000
Proceeds from (payments on) derivative instruments, net	515,000	(4,244,000)
Net cash used in investing activities	(63,529,000)	(104,112,000)
Cash flows from financing activities
Proceeds from long-term debt	30,000,000	79,000,000
Repayment of long-term debt	(171,000)	(146,000)
Principal payments under financing lease obligations	(699,000)	(661,000)
Payment of debt issuance costs and other financing fees	(20,000)	0
Treasury stock purchased	(463,000)	0
Net cash provided by financing activities	28,647,000	78,193,000
Net decrease in cash, cash equivalents, and restricted cash	(26,328,000)	(15,543,000)
Cash, cash equivalents, and restricted cash at beginning of period	37,446,000	27,732,000
Cash, cash equivalents, and restricted cash at end of period	$ 11,118,000	$ 12,189,000

Nature of operations and summar

Nature of operations and summary of significant accounting policies	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Nature of operations and summary of significant accounting policies	Nature of operations and summary of significant accounting policies Nature of operations Chaparral Energy, Inc. and its subsidiaries (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products include crude oil, natural gas and natural gas liquids. Interim financial statements The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018 , as amended. The financial information as of March 31, 2019 , and for the three months ended March 31, 2019 and 2018 , is unaudited. The financial information as of December 31, 2018 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 . In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2019 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2019 . 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 maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of March 31, 2019 , cash with a recorded balance totaling approximately $9,127 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. Accounts receivable We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following: March 31, December 31, Joint interests $ 37,640 $ 31,573 Accrued commodity sales 23,165 30,287 Derivative settlements 1,056 2,092 Other 1,793 3,375 Allowance for doubtful accounts (1,002 ) (1,240 ) $ 62,652 $ 66,087 Inventories Inventories consisted of the following: March 31, December 31, Equipment inventory $ 3,570 $ 3,663 Commodities 531 574 Inventory valuation allowance (178 ) (178 ) $ 3,923 $ 4,059 Property and equipment, net Major classes of property and equipment are shown in the following table: March 31, December 31, Furniture and fixtures $ 520 $ 520 Automobiles and trucks 4,333 3,548 Machinery and equipment 21,714 21,482 Office and computer equipment 6,417 6,183 Building and improvements 18,738 18,693 51,722 50,426 Less accumulated depreciation and amortization 14,283 12,449 37,439 37,977 Land 5,119 5,119 $ 42,558 $ 43,096 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. Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves. In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Effective Date, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play. The costs of unevaluated oil and natural gas properties consisted of the following: March 31, December 31, Leasehold acreage $ 419,413 $ 427,206 Capitalized interest 13,938 11,377 Wells and facilities in progress of completion 50,670 28,033 Total unevaluated oil and natural gas properties excluded from amortization $ 484,021 $ 466,616 Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. Our estimates of oil and natural gas reserves as of March 31, 2019 , and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. We recorded a ceiling test write-down to our oil and natural gas properties of $49,722 for the three months ended March 31, 2019. We recorded no impairments for the three months ended March 31, 2018. The 2019 loss is reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. Producer imbalances. We account for natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at March 31, 2019 , and December 31, 2018 , were immaterial. Revenue recognition In May 2014, the Financial Accounting Standards Board ("FASB") issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”). ASC 606 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 following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported: Three months ended March 31, 2019 2018 Revenues: Oil $ 32,802 $ 43,050 Natural gas 11,206 8,736 Natural gas liquids 9,217 9,591 Gross commodity sales 53,225 61,377 Transportation and processing (4,606 ) (3,488 ) Net commodity sales $ 48,619 $ 57,889 Please see “Note 16—Revenue recognition” in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing , measurement and contract assets and liabilities. Income taxes The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Significant management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three months ended March 31, 2019 and 2018, respectively. The consistent effective tax rate for the three months ended March 31, 2019 is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset. Despite the Company’s net loss for the three month period ended March 31, 2019, we did no t record any net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. 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 our 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 our net deferred tax asset is necessary, we likely will not have any additional deferred income tax expense or benefit. The benefit of an uncertain tax position taken, or expected to be taken, on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at March 31, 2019, or December 31, 2018. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code of 1986, as amended ("IRC") Section 382 on March 21, 2017. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the three month period ended March 31, 2019, or any intervening period since March 21, 2017. Other expense Other expense consisted of the following: Three months ended March 31, 2019 2018 Restructuring $ — $ 425 Subleases 403 403 Total other expense $ 403 $ 828 Restructuring . We previously incurred exit costs in conjunction with our EOR asset divestiture, which are predominantly comprised of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final slate of employees terminated as a result of the divestiture. Subleases . Our subleases are comprised of CO 2 compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, the financing leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases. Please see “Note 5— Leases” for our disclosure on leases. Joint development agreement On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”), pursuant to which BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3,400 and $4,000 per gross well. The JDA wells, which will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. The JDA provides us with a means to accelerate the delineation of our position within our Garfield and Canadian County acreage, realizing further efficiencies and holding additional acreage by production, and potentially adding reserves. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15% ) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all JDA wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties entitled to revenues and paying lease operating expenses based on their working interest. Our drilling and completion costs to date have been exceeding well cost caps specified under the JDA primarily due to inflation in the cost of oilfield services as a result of the rebound in industry conditions. In our negotiation with BCE to cover the inflationary cost increases, BCE had indicated willingness to increase the per well cost caps on remaining wells in exchange for adding more wells to the current program. Since we have achieved our goals to utilize the JDA as a means to delineate our acreage Garfield and Canadian counties, Oklahoma, we do not currently plan for any expansion of the JDA. For the three months ended March 31, 2019 , we have therefore recorded additions to oil and natural gas properties of $3,182 in drilling and completion costs on JDA wells that have exceeded the well cost caps specified under the JDA. Reorganization items Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy in March 2017, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. “Professional fees” in the table below for periods subsequent to the emergence from bankruptcy are comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows: Three months ended March 31, 2019 2018 Loss (gain) on the settlement of liabilities subject to compromise $ — $ 48 Professional fees 463 989 Total reorganization items $ 463 $ 1,037 Recently adopted accounting pronouncements In February 2016, the FASB issued authoritative guidance that supersedes previous lease recognition requirements and requires entities to recognize leases on-balance sheet and disclose key information about leasing arrangements. Please see “Note 5—Leases” for our disclosure regarding adoption of this update. Recently issued accounting pronouncements 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 to offset potential losses 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.

Earnings per share

Earnings per share	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Earnings per share	Earnings per share Although we previously had both Class A and Class B common stock outstanding, where both classes of common stock shared equally in voting power, dividends and undistributed earnings, on December 19, 2018, all outstanding shares of our Class B common stock converted into the same number of shares of Class A common stock. A reconciliation of the components of basic and diluted EPS is presented below: Three months ended March 31, (in thousands, except share and per share data) 2019 2018 Numerator for basic and diluted earnings per share Net loss $ (103,540 ) $ (11,442 ) Denominator for basic earnings per share Weighted average common shares - Basic for Class A and Class B (1) 45,456,214 45,143,297 Denominator for diluted earnings per share Weighted average common shares - Diluted for Class A and Class B (1) 45,456,214 45,143,297 Earnings per share Basic for Class A and Class B (1) $ (2.28 ) $ (0.25 ) Diluted for Class A and Class B (1) $ (2.28 ) $ (0.25 ) Participating securities excluded from earnings per share calculations Warrants (2) — 140,023 Unvested restricted stock awards 886,482 1,589,332 ________________________________ (1) Effective December 19, 2018, all our outstanding Class B shares were converted to Class A shares and subsequently, all our outstanding common stock was comprised only of Class A common stock. Earnings per share for the three months ended March 31, 2018 reflects earnings per share for Class A and Class B common stock in aggregate whereas earnings per share for the three months ended March 31, 2019 reflects earnings per share for Class A common stock. (2) The warrants to purchase shares of our Class A common stock are antidilutive for three months ended March 31, 2018, due to the exercise price exceeding the average price of our Class A shares and due to the net loss we incurred. These warrants expired on June 30, 2018.

Supplemental disclosures to the

Supplemental disclosures to the consolidated statements of cash flows	3 Months Ended
	Mar. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental disclosures to the consolidated statements of cash flows	Supplemental disclosures to the consolidated statements of cash flows Three months ended March 31, 2019 2018 Net cash provided by operating activities included: Cash payments for interest $ 14,681 $ 2,206 Interest capitalized (3,492 ) (1,521 ) Cash payments for reorganization items 394 410 Non-cash investing activities included: Asset retirement obligation additions and revisions 76 213 Leasing right of use asset additions (see Note 5 - Leases) 670 — Change in accrued oil and gas capital expenditures 15,174 705

Debt

Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt	Debt As of the dates indicated, long-term debt and financing leases consisted of the following: March 31, December 31, 8.75% Senior Notes due 2023 $ 300,000 $ 300,000 Credit Facility 30,000 — Real estate mortgage note 8,433 8,588 Installment note payable 337 354 Financing lease obligations 11,648 11,677 Unamortized debt issuance costs (12,366 ) (13,148 ) Total debt, net 338,052 307,471 Less current portion 11,854 12,371 Total long-term debt, net $ 326,198 $ 295,100 Credit Facility The Credit Facility is a $750,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022 . Availability under our Credit Facility 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 or around May 1 and November 1 of each year. Our borrowing base under the Credit Facility as of March 31, 2019 , was $325,000 with the unused portion, after taking into account letters of credit and outstanding borrowings, amounting to $294,131 . Availability on the Credit Facility as of March 31, 2019 , was $153,956 . Our availability was lower than the unused borrowing base capacity as a result of the constraints placed by the Ratio of Total Debt to EBITDAX covenant discussed below. As of March 31, 2019 , our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the Credit Facility), plus the Applicable Margin (as defined in the Credit Facility), which resulted in a weighted average interest rate of 4.49% . The Credit Facility contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the Credit Facility) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the Credit Facility) of no greater than 4.0 to 1.0 calculated on a trailing four -quarter basis. We were in compliance with these financial covenants as of March 31, 2019 . The Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8—Debt” in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of the material provisions of our Credit Facility. On May 2, 2019, we entered into the Third Amendment to the Tenth Restated Credit Agreement, among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and Royal Bank of Canada, as administrative agent (the “Third Amendment”). The Third Amendment, which was effective March 31, 2019, reaffirmed our borrowing base at the same level as it was at the beginning of 2019, at $325,000 . Senior Notes On June 29, 2018, we completed the issuance and sale at par of $300,000 in aggregate principal amount of our Senior Notes in a private placement under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The Senior Notes bear interest at a rate of 8.75% per year beginning June 29, 2018 (payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2019 ) and will mature on July 15, 2023 . The Senior Notes are the Company’s senior unsecured obligations and rank equal in right of payment with all of the Company’s existing and future senior indebtedness, senior to all of the Company’s existing and future subordinated indebtedness and effectively subordinated to all of the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness. The Senior Notes contain customary covenants, certain callable provisions and events of default. Please see “Note 8—Debt” in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of the material provisions of our Senior Notes.

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Leases	Leases In February 2016, the FASB established Accounting Standards Codification ("ASC") Topic 842, Leases (“ASC 842”) which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use ("ROU") model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”). We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Upon adoption of ASC 842, we carried over our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value. Financing leases In 2013, we entered into lease financing agreements with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO 2 compressors owned by us. The lease financing obligations are for terms of 84 months 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. There are no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract has not been modified and there have been no triggering events subsequent to our adoption of ASC 842, we have not performed any reassessment of the lease. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8% . Minimum lease payments are approximately $3,181 annually. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank. During 2019, we entered into lease financing agreements for our fleet trucks for $670 . We intend to add additional vehicles throughout 2019 under the same fleet leasing arrangement. The lease financing obligations are for 48 -month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor's remaining unamortized cost in the vehicle. At the end of the lease term, the lessor's remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees and nonlease components under these leases. Operating leases We also have operating leases for CO 2 compressors previously deployed in our EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, are for terms of 84 months without any specified purchase options. There are no residual value guarantees and nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank. During the fourth quarter of 2018, we entered into 15 -month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs for which we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. We record the difference between the actual daily rate and the minimum rate as a variable lease cost. The daily rate includes a non-lease labor component for which we have elected not to separate from the lease component. Short term leases Our short term leases are those with lease terms of 12 months of less and are generally comprised of wellhead compressors and generators with terms ranging from one month to six months . We have also leased drilling rigs for short durations which, in the past, may have been on a well-by-well basis or for terms up to six months . As of March 31, 2019 , we have one drilling rig with one month remaining on a four month lease term. Subleases As discussed above, our subleases are comprised of CO 2 compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, the financing leases were included in our full cost amortization base and as such subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases. Lease assets and liabilities Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of March 31, 2019 as follows: As of March 31, 2019 Operating leases Financing leases Right of use asset: Right of use assets from operating leases $ 12,064 $ — Plant, property and equipment, net (1) — 11,488 Total lease assets $ 12,064 $ 11,488 Lease liability: Account payable and accrued liabilities $ 9,757 $ — Long-term debt and financing leases, classified as current — 11,152 Long-term debt and financing leases, less current maturities — 496 Noncurrent operating lease obligations 2,307 — Total lease liabilities $ 12,064 $ 11,648 ________________________________ (1) CO 2 compressors included in Machinery and equipment and fleet vehicles included in automobiles and trucks. See “Note 1—Nature of operations and summary of significant accounting policies.” Our income, expenses and cash flows related to our leases is as follows for the three months ended March 31, 2019 : Three months ended March 31, 2019 Lease cost Finance lease cost: Amortization of right-of-use assets $ 693 Interest on lease liabilities 113 Operating lease cost 308 Short-term lease cost 129 Variable lease cost 95 Sublease income (1,198 ) Total lease cost $ 140 Capitalized operating lease cost (1) $ 3,335 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases (113 ) Operating cash flows from operating leases (308 ) Investing cash flows for operating leases (1,023 ) Financing cash flows for finance leases (699 ) Right-of-use assets obtained in exchange for new finance lease liabilities 670 Weighted-average remaining lease term - finance leases 0.8 years Weighted-average remaining lease term - operating leases 1.3 years Weighted-average discount rate - finance leases 3.96 % Weighted-average discount rate - operating leases 13.22 % ________________________________ (1) The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets. Our rent expense for the three months ended March 31, 2018, was $ 968 . Discount rate Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments. Lease maturities Our lease payments for each of the next five years and thereafter are as follows: As of March 31, 2019 As of December 31, 2018 (1) Operating leases Financing leases Operating leases Financing leases 2019 $ 10,282 $ 11,366 $ 13,890 $ 12,332 2020 1,233 178 1,330 — 2021 1,292 178 1,297 — 2022 274 178 278 — 2023 205 21 205 — Thereafter — — — — Total minimum lease payments 13,286 11,921 17,000 12,332 Less: imputed interest 1,222 273 * * Total lease liability 12,064 11,648 * * Less: current maturities of lease obligations 9,757 11,152 * * Long-term lease obligations $ 2,307 $ 496 * * ________________________________ (1) Represents undiscounted firm commitments as of December 31, 2018 * Disclosure not required under ASC 840. Method of adoption We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit. Reconciliation of Balance Sheet Statement In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows: As of January 1, 2019 Balances upon adoption Balances without adoption of ASC 842 Effect of change Assets Right of use asset from operating leases, net $ 14,999 $ — $ 14,999 Liabilities Accounts payable and accrued liabilities 12,467 — 12,467 Noncurrent operating lease obligation 2,532 — 2,532
Leases	Leases In February 2016, the FASB established Accounting Standards Codification ("ASC") Topic 842, Leases (“ASC 842”) which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842 was subsequently amended by Accounting Standards Update (“ASU”) No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. The new standard establishes a right-of-use ("ROU") model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases except those with a term of 12 months or less. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. We adopted the new standard on its effective date of January 1, 2019, which is also our date of initial application. Consequently, we have not updated financial information nor provided disclosures required under the new standard for dates and periods before January 1, 2019. Our disclosures for dates and periods before January 1, 2019, are provided in accordance with the requirements of ASC Topic 840, Leases (“ASC 840”). We have elected the package of transition practical expedients, which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs. Upon adoption of ASC 842, we carried over our existing capital lease obligations (now “financing leases” under ASC 842) and capital lease asset (now “right of use asset” under ASC 842) at their previous carrying value. Financing leases In 2013, we entered into lease financing agreements with U.S. Bank for $24,500 through the sale and subsequent leaseback of existing CO 2 compressors owned by us. The lease financing obligations are for terms of 84 months 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. There are no residual value guarantees and nonlease components under these leases. At the inception of the lease, our measurement of the lease liability assumed that the mid-term purchase option would be exercised. Since the lease contract has not been modified and there have been no triggering events subsequent to our adoption of ASC 842, we have not performed any reassessment of the lease. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8% . Minimum lease payments are approximately $3,181 annually. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank. During 2019, we entered into lease financing agreements for our fleet trucks for $670 . We intend to add additional vehicles throughout 2019 under the same fleet leasing arrangement. The lease financing obligations are for 48 -month terms with the option for us to purchase the vehicle at any time during the lease term by paying the lessor's remaining unamortized cost in the vehicle. At the end of the lease term, the lessor's remaining unamortized cost in the vehicle will be a de minimis amount and hence ownership of the vehicle can be transferred to us at minimal cost. There are no residual value guarantees and nonlease components under these leases. Operating leases We also have operating leases for CO 2 compressors previously deployed in our EOR operations. The operating lease obligations, which we entered into in 2014 and 2016, are for terms of 84 months without any specified purchase options. There are no residual value guarantees and nonlease components under these leases. In conjunction with the sale of our EOR assets in November 2017, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank. During the fourth quarter of 2018, we entered into 15 -month leasing arrangements for two drilling rigs. These agreements specify a minimum daily rate on the rigs for which we utilize to measure the lease liability upon adoption of ASC 842. The actual daily rate may vary from the minimum rate depending on whether the rig is being mobilized, demobilized, engaged in drilling or on standby. We record the difference between the actual daily rate and the minimum rate as a variable lease cost. The daily rate includes a non-lease labor component for which we have elected not to separate from the lease component. Short term leases Our short term leases are those with lease terms of 12 months of less and are generally comprised of wellhead compressors and generators with terms ranging from one month to six months . We have also leased drilling rigs for short durations which, in the past, may have been on a well-by-well basis or for terms up to six months . As of March 31, 2019 , we have one drilling rig with one month remaining on a four month lease term. Subleases As discussed above, our subleases are comprised of CO 2 compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, the financing leases were included in our full cost amortization base and as such subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases. Lease assets and liabilities Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of March 31, 2019 as follows: As of March 31, 2019 Operating leases Financing leases Right of use asset: Right of use assets from operating leases $ 12,064 $ — Plant, property and equipment, net (1) — 11,488 Total lease assets $ 12,064 $ 11,488 Lease liability: Account payable and accrued liabilities $ 9,757 $ — Long-term debt and financing leases, classified as current — 11,152 Long-term debt and financing leases, less current maturities — 496 Noncurrent operating lease obligations 2,307 — Total lease liabilities $ 12,064 $ 11,648 ________________________________ (1) CO 2 compressors included in Machinery and equipment and fleet vehicles included in automobiles and trucks. See “Note 1—Nature of operations and summary of significant accounting policies.” Our income, expenses and cash flows related to our leases is as follows for the three months ended March 31, 2019 : Three months ended March 31, 2019 Lease cost Finance lease cost: Amortization of right-of-use assets $ 693 Interest on lease liabilities 113 Operating lease cost 308 Short-term lease cost 129 Variable lease cost 95 Sublease income (1,198 ) Total lease cost $ 140 Capitalized operating lease cost (1) $ 3,335 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases (113 ) Operating cash flows from operating leases (308 ) Investing cash flows for operating leases (1,023 ) Financing cash flows for finance leases (699 ) Right-of-use assets obtained in exchange for new finance lease liabilities 670 Weighted-average remaining lease term - finance leases 0.8 years Weighted-average remaining lease term - operating leases 1.3 years Weighted-average discount rate - finance leases 3.96 % Weighted-average discount rate - operating leases 13.22 % ________________________________ (1) The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets. Our rent expense for the three months ended March 31, 2018, was $ 968 . Discount rate Whenever possible, we utilize the implied rate in our lease agreements to measure our lease liabilities. In the absence of a readily available implied rate, we utilize our incremental borrowing rate. The incremental borrowing rate is the rate of interest that a lessee would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. The lease liabilities we recorded on our balance sheet on the effective date of ASC 842 were measured utilizing an incremental borrowing rate derived from the yield on our unsecured Senior Notes and adjusted to a collateralized basis utilizing a recovery rate model that uses observed recovery rates on defaulted debt instruments. Lease maturities Our lease payments for each of the next five years and thereafter are as follows: As of March 31, 2019 As of December 31, 2018 (1) Operating leases Financing leases Operating leases Financing leases 2019 $ 10,282 $ 11,366 $ 13,890 $ 12,332 2020 1,233 178 1,330 — 2021 1,292 178 1,297 — 2022 274 178 278 — 2023 205 21 205 — Thereafter — — — — Total minimum lease payments 13,286 11,921 17,000 12,332 Less: imputed interest 1,222 273 * * Total lease liability 12,064 11,648 * * Less: current maturities of lease obligations 9,757 11,152 * * Long-term lease obligations $ 2,307 $ 496 * * ________________________________ (1) Represents undiscounted firm commitments as of December 31, 2018 * Disclosure not required under ASC 840. Method of adoption We adopted ASC 842 effective January 1, 2019, using the modified retrospective approach. Based on an assessment of our leasing contracts, we did not record a cumulative effect adjustment to the opening balance of accumulated deficit. Reconciliation of Balance Sheet Statement In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows: As of January 1, 2019 Balances upon adoption Balances without adoption of ASC 842 Effect of change Assets Right of use asset from operating leases, net $ 14,999 $ — $ 14,999 Liabilities Accounts payable and accrued liabilities 12,467 — 12,467 Noncurrent operating lease obligation 2,532 — 2,532

Derivative instruments

Derivative instruments	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative instruments	Derivative instruments Overview Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, and basis protection swaps. The following table summarizes our crude oil derivatives outstanding as of March 31, 2019 : Period and type of contract Volume MBbls Weighted average fixed price per Bbl 2019 Oil swaps 1,935 $ 56.06 Oil roll swaps 380 $ 0.49 2020 Oil swaps 2,007 $ 50.56 Oil roll swaps 410 $ 0.38 2021 Oil swaps 690 $ 46.24 Oil roll swaps 150 $ 0.30 The following table summarizes our natural gas derivatives outstanding as of March 31, 2019 : Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2019 Natural gas swaps 11,713 $ 2.85 Natural gas basis swaps 8,882 $ (0.61 ) 2020 Natural gas swaps 6,000 $ 2.75 Natural gas basis swaps 3,600 $ (0.46 ) The following table summarizes our natural gas liquid derivatives outstanding as of March 31, 2019 : Period and type of contract Volume Thousands of Gallons Weighted average fixed price per gallon 2019 Natural gasoline swaps 3,570 $ 1.39 Propane swaps 8,232 $ 0.74 2020 Natural gasoline swaps 1,890 $ 1.39 Propane swaps 4,284 $ 0.74 Subsequent to March 31, 2019 and through May 7, 2019, we entered into additional derivative contracts, including 195 MBbls of crude oil collars scheduled to settle in 2020 with a weighted average purchased put price of $55.00 per barrel and sold call of $66.42 per barrel, and the following natural gas liquids contracts: Period and type of contract Volume Thousands of Gallons Weighted average fixed price per Gallon 2019 Iso butane 1,344 $ 0.72 Natural gasoline 1,848 $ 1.24 N-butane 3,822 $ 0.70 Propane 3,864 $ 0.64 2020 Iso butane 630 $ 0.72 Natural gasoline 882 $ 1.24 N-butane 1,722 $ 0.70 Propane 1,890 $ 0.64 Effect of derivative instruments on the consolidated balance sheets All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7—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 at March 31, 2019 As at December 31, 2018 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 891 $ (685 ) $ 206 $ 833 $ (488 ) $ 345 Crude oil derivative contracts 1,851 (30,764 ) (28,913 ) 24,208 (4,452 ) 19,756 NGL derivative contracts 1,857 — 1,857 4,581 — 4,581 Total derivative instruments 4,599 (31,449 ) (26,850 ) 29,622 (4,940 ) 24,682 Less: Netting adjustments (1) (4,599 ) 4,599 — (3,398 ) 3,398 — Derivative instruments - current — (10,874 ) (10,874 ) 24,025 — 24,025 Derivative instruments - long-term $ — $ (15,976 ) $ (15,976 ) $ 2,199 $ (1,542 ) $ 657 ________________________________ (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 counterparties are netted only to the extent that they relate 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 “Derivative (losses) gains” in the consolidated statements of operations. “Derivative (losses) gains” in the consolidated statements of operations are comprised of the following: Three months ended March 31, 2019 2018 Change in fair value of commodity price derivatives $ (51,531 ) $ (12,257 ) Settlements (paid) received on commodity price derivatives 515 (4,244 ) Total derivative losses $ (51,016 ) $ (16,501 )

Fair value measurements

Fair value measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair value measurements	Fair value measurements Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows: • Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. • Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. • Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Recurring fair value measurements As of March 31, 2019 , and December 31, 2018 , our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 6—Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price swaps and oil roll swaps which are valued using an income approach. Future cash flows from the commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market price. Our derivative contracts classified as Level 3 consisted of collars and natural gas basis swaps. 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 and proprietary pricing curves. 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 our counterparty credit risk for derivative assets. The fair value hierarchy for our financial assets and liabilities is shown by the following table: As at March 31, 2019 As at December 31, 2018 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 4,598 $ (30,910 ) $ (26,312 ) $ 29,370 $ (4,718 ) $ 24,652 Significant unobservable inputs (Level 3) 1 (539 ) (538 ) 252 (222 ) 30 Netting adjustments (1) (4,599 ) 4,599 — (3,398 ) 3,398 — $ — $ (26,850 ) (26,850 ) $ 26,224 $ (1,542 ) $ 24,682 ________________________________ (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 counterparties 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, were as follows for the periods presented: Three months ended March 31, Net derivative assets (liabilities) 2019 2018 Beginning balance $ 30 $ (295 ) Realized and unrealized (losses) gains included in derivative losses (981 ) (432 ) Settlements paid 413 108 Ending balance $ (538 ) $ (619 ) (Losses) gains relating to instruments still held at the reporting date included in derivative losses for the period $ (537 ) $ (380 ) Nonrecurring fair value measurements Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first three months of 2019 and 2018 were escalated using an annual inflation rate of 2.25% and 2.26% , respectively. The estimated future costs to dispose of properties added during the three months ended March 31, 2019 and 2018 , were discounted with a credit-adjusted risk-free rate was 12.35% and 6.92% , respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 8—Asset retirement obligations” for additional information regarding our asset retirement obligations. Fair value of other financial instruments Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and 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 were as follows: March 31, 2019 December 31, 2018 Level 2 Carrying value (1) Estimated fair value Carrying value (1) Estimated fair value 8.75% Senior Notes due 2023 $ 300,000 $ 207,183 $ 300,000 $ 213,618 Credit Facility 30,000 30,000 — — Other secured debt 8,770 8,770 8,942 8,942 ________________________________ (1) The carrying value excludes deductions for debt issuance costs. The carrying value of our Credit Facility and other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms, are variable and incorporate a measure of our credit risk. The fair value of our Senior Notes was estimated based on quoted market prices. Counterparty credit risk Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of March 31, 2019 , the counterparties to our open derivative contracts consisted of eight financial institutions, of which all were lenders under our Credit Facility. The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting assets (liabilities) Net assets (liabilities) Derivatives (1) Amounts outstanding under credit facilities (2) Net amount March 31, 2019 Derivative assets $ 4,599 $ (4,599 ) $ — $ — $ — $ — Derivative liabilities (31,449 ) 4,599 (26,850 ) — — (26,850 ) $ (26,850 ) $ — $ (26,850 ) $ — $ — $ (26,850 ) December 31, 2018 Derivative assets $ 29,622 $ (3,398 ) $ 26,224 $ (1,542 ) $ — $ 24,682 Derivative liabilities (4,940 ) 3,398 (1,542 ) 1,542 — — $ 24,682 $ — $ 24,682 $ — $ — $ 24,682 ________________________________ (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. (2) The amount outstanding under our Credit Facility that is available to offset our net derivative assets due from counterparties that are lenders under our Credit Facility. We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default on our Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $31,449 before offsets at March 31, 2019 .

Asset retirement obligations

Asset retirement obligations	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations The following table provides a summary of our asset retirement obligation activity: Balance at January 1, 2019 $ 23,147 Liabilities incurred in current period 66 Liabilities settled or disposed in current period (271 ) Revisions in estimated cash flows 10 Accretion expense 354 Balance at March 31, 2019 $ 23,306 Less current portion included in accounts payable and accrued liabilities 1,058 Asset retirement obligations, long-term $ 22,248 See “Note 7—Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

Deferred compensation

Deferred compensation	3 Months Ended
	Mar. 31, 2019
Share-based Compensation [Abstract]
Deferred compensation	Deferred compensation Cash Incentive Plan We adopted the Long-Term Cash Incentive Plan (the “Cash LTIP”) on August 7, 2015. The 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. A summary of compensation expense for the Cash LTIP is presented below: Three months ended March 31, 2019 2018 Cash LTIP expense (net of amounts capitalized) $ 91 $ 95 Cash LTIP payments — 17 As of March 31, 2019 , the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,487 . Beginning in October 2018, we ceased issuing cash grants under the Cash LTIP plan and instead are issuing restricted stock units ("RSUs") to our employees. 2017 Management Incentive Plan In 2017, we adopted the Chaparral Energy, Inc. Management Incentive Plan (the “MIP”). The MIP provides for the following types of awards: options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards. The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to the MIP was initially set at 3,388,832 subject to changes in the event additional shares of common stock are issued under our Reorganization Plan. The MIP contemplates that any award granted under the plan may provide for the earlier termination of restrictions and acceleration of vesting in the event of a Change in Control, as may be described in the particular award agreement. Pursuant to the MIP, we have granted restricted stock to executive employees and members of our Board of Directors (the “Board”). Grants awarded to executives are generally comprised of shares for which 75% are subject to service vesting conditions (the “Time Shares”) and 25% are subject to performance or market-based vesting conditions (the “Performance Shares”). All grants to the Board were Time Shares. Both the Time and Performance Shares are classified as equity-based awards. Compensation cost is generally recognized and measured according to the grant date fair value of the awards which are based on the market price of our common stock for awards with service and performance conditions. The Time Shares vest in equal annual installments over the three -year vesting period. The Performance Shares vest in three tranches annually according to performance or market-based conditions established each year which generally relate to profitability, stock returns, drilling results and other strategic goals. Vesting conditions for Performance Shares vesting in 2019 were established and approved by our Board in March 2019 and we have commenced recognizing expense for the related shares in the first quarter of 2019. Our Board established that all Performance Shares scheduled to vest in 2019 shall be subject to a market condition that is based on our stock return relative to a group of peer companies. Expense on these awards is based on a fair value that incorporates the probability of vesting. We utilized a Monte Carlo simulation to estimate the fair value of the market based award. The simulation utilized a risk free rate of 2.52% and volatility of 64.1% to arrive at a fair value of $ 4.66 per restricted share. These inputs are considered to be Level 3 inputs within the fair value hierarchy. A summary of our restricted stock activity pursuant to our MIP is presented below: Time Shares Performance Shares Weighted average award date fair value Restricted shares Vest date fair value Weighted average award date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2019 $ 20.06 818,206 $ 20.12 $ 125,528 Granted $ 7.97 78,378 $ 7.97 $ 15,000 Vested $ 20.05 (73,517 ) $ 525 $ — $ — Forfeited $ 20.05 (73,515 ) $ 20.05 $ (23,598 ) Unvested and outstanding at March 31, 2019 $ 18.79 749,552 $ 18.57 $ 116,930 Beginning in October 2018, we have issued RSUs under our MIP to certain non-executive employees in lieu of cash awards. Certain RSUs are to be settled in stock upon vesting while others are to be settled in cash. The stock-settled RSUs are classified as equity awards while the cash settled RSUs are classified as liability awards. These awards, which are service-based, will vest in equal installments over a 3 year period. See “Note 1—Nature of operations and summary of significant accounting policies” in Item 8 Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of accounting policies regarding our RSUs. A summary of our RSU activity is presented below: Stock-settled RSUs Cash-settled RSUs Weighted average award date fair value Restricted units Weighted average award date fair value Restricted units ($ per share) ($ per share) Unvested and outstanding at January 1, 2019 $ 17.66 89,633 $ 17.66 $ 37,196 Granted $ — — $ 6.37 $ 1,570 Forfeited $ 17.66 (2,554 ) $ 17.66 $ (1,136 ) Unvested and outstanding at March 31, 2019 $ 17.66 87,079 $ 17.19 $ 37,630 Companywide stock award New employees are eligible for a grant of 100 shares subsequent to being employed for a certain period of time. There are no vesting requirements for these awards and thus compensation is recognized in full on the award date based on the closing price of our common stock on that date. In January 2019, 700 shares were awarded to new employees. Stock-based compensation cost Compensation cost is calculated net of forfeitures. We recognize the impact of forfeitures due to employee terminations in expense as they occur instead of incorporating an estimate of such forfeitures. For awards with performance conditions, we will assess the probability that a performance condition will be achieved at each reporting period to determine whether and when to recognize compensation cost. For awards with market conditions, expense is recognized on the entire value of the award regardless of the vesting outcome so long as the participant remains employed. 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. Stock-based compensation expense is as follows for the periods indicated: Three months ended March 31, 2019 2018 Stock-based compensation cost $ 1,460 $ 5,580 Less: stock-based compensation cost capitalized (626 ) (957 ) Stock-based compensation expense $ 834 $ 4,623 Number of vested shares repurchased 80,422 — Payments for stock-based compensation $ 463 $ 1,422 Based on a quarter end market price of $5.70 per share of our Class A common stock, the aggregate intrinsic value of all restricted shares and stock settled RSUs outstanding was $5,435 as of March 31, 2019 . The repurchases of shares and associated payments disclosed above were primarily for tax withholding and tax liabilities and are reflected as treasury stock transactions on our consolidated statements of stockholders’ equity. As of March 31, 2019 , and December 31, 2018 , accrued payroll and benefits payable included for stock-based compensation costs expected to be settled within the next twelve months were $37 and $17 , respectively, all of which relates to our cash-settled RSUs. Unrecognized stock-based compensation cost of approximately $4,999 as of March 31, 2019 , is expected to be recognized over a weighted-average period of 1.3 years .

Commitments and contingencies

Commitments and contingencies	3 Months Ended
	Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Commitments and contingencies Standby letters of credit (“Letters”) available under our Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had Letters outstanding totaling $869 as of each of March 31, 2019 and December 31, 2018 . When amounts under the Letters are paid by the lenders, interest accrues on the amount paid at the same interest rate applicable to borrowings under the Credit Facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the three months ended March 31, 2019 or 2018 . Litigation and Claims Chapter 11 Proceedings. Commencement of the Chapter 11 proceedings 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 (“Petition Date”), and the claims remain subject to Bankruptcy Court jurisdiction. With respect to the proofs of claim asserted in the Chapter 11 Cases arising from the proceedings or actions below which were initiated prior to the Petition Date, we are unable to estimate the amount of such claims that will be allowed by the Bankruptcy Court due to, among other things, the complexity and number of legal and factual issues which are necessary to determine the amount of such claims and uncertainties related to the nature of defenses asserted in connection with the claims, the potential size of the putative classes, and the types of the properties and scope of agreements related to such claims. As a result, no reserves were established in respect of such proofs of claims or any of the proceedings or actions described below. To the extent that any of the legal proceedings were filed prior to the Petition Date and result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company or, if the amount of such claim is below the convenience class threshold, through cash settlement. As of March 31, 2019 , there are in excess of 100 remaining claims subject to Bankruptcy Court jurisdiction. Of the total alleged dollar amount of these unresolved claims, nearly all, as measured by the alleged amount of such claims, is comprised of claims from the Naylor Farms case, the W.H. Davis case and the CLO case described below. If the Bankruptcy Court were to allow the remaining unresolved proofs of claims from these cases in the full amount asserted therein, the Company, pursuant to the Plan of Reorganization, would be required to issue additional shares to the holders of such allowed proofs of claim, which could result in dilution to existing stockholders. Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C (the “Naylor Farms case”). 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 non-governmental Royalty Interest owners from crude 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. Plaintiffs indicated they seek damages in excess of $5,000 , the majority of which would be comprised of interest and may increase with the passage of time. We 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 Naylor Trial 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. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court. Subsequently the bankruptcy stay was lifted for the limited purpose of determining the class certification issue. 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. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 3, 2019, our appeal of that class certification was denied by the Tenth Circuit Court of Appeals (the “Tenth Circuit”). In addition to filing claims on behalf of the named and putative plaintiffs, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. On June 7, 2017 we appealed the Bankruptcy Court order to the United States District Court for the District of Delaware. Pursuant to the Reorganization Plan, if the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and are objecting to the claims both individually and on a class-wide basis. W. H. Davis Family Limited Partnership Claims in the Company’s Chapter 11 Bankruptcy Cases (the “W.H. Davis case”). The W. H. Davis Family Limited Partnership (“Davis”) filed Proofs of Claim (Nos. 1819 and 1835) in the Company’s Chapter 11 Cases. Davis claims that Chaparral owes Davis $17,262 as the result of Chaparral’s alleged diversion of CO2 from the Camrick Unit and the North Perryton Unit to the Farnsworth Unit. All these units were divested by the Company as part of its EOR asset sale in November 2017. The Camrick Unit was a tertiary recovery project located in Beaver County and Texas County, Oklahoma. The North Perryton Unit was a tertiary recovery project located in Ochiltree County, Texas. The Company was previously the operator of the Camrick and North Perryton Units and owned approximately 60% of the working interest in those units. Davis owns approximately 40% of the working interests in those units. The Company also operated the Farnsworth Unit which was a tertiary recovery project located in Ochiltree County, Texas. The Company previously owned 100% of the working interests in the Farnsworth Unit. Davis contends that the Company was required to deliver all available CO 2 sourced from the Agrium nitrogen fertilizer plant in Borger, Texas, to the Camrick and North Perryton Units and its diversion of a portion of the available CO 2 to the Farnsworth Unit constitutes a breach of contractual and fiduciary duties owed to Davis. Davis contends that the diversion has resulted in a decrease of oil production and reserves in the Camrick Unit and the North Perryton Unit. Davis contends that Chaparral caused the diversion of CO 2 from the Camrick and North Perryton Units to the Farnsworth Unit in order to profit from increased production at the Farnsworth Unit to the detriment of Davis. The Company disputes Davis’ allegations and specifically denies that it has any contractual or fiduciary obligation to Davis as alleged in the Proofs of Claim. The Company filed objections to the Proofs of Claim in the Chapter 11 proceeding. This proceeding is pending in the Bankruptcy Court. The Bankruptcy Judge has ordered Davis and the Company to participate in a mediation of the dispute. Pursuant to the Reorganization Plan, if Davis ultimately prevails on the merits of its claims, any liability arising under the judgment or settlement would be satisfied through the issuance of stock in the Company. The Commissioners of the Land Office of the State of Oklahoma’s Claims in the Company’s Chapter 11 Bankruptcy Cases (the “CLO case”). The Commissioners of the Land Office of the State of Oklahoma (“CLO”) claims that the Company is the lessee of mineral interests owned by the State of Oklahoma that are administered by the CLO. The CLO alleges that the Company has failed to pay royalties or has underpaid royalties owed to the CLO under these mineral leases and the CLO’s regulations. The CLO’s Proofs of Claims Nos. 2130 and 2131 allege non-payment of royalties and seek recovery of $1,697 in allegedly unpaid royalties and related interest. The CLO’s Proofs of Claim Nos. 2132, 2133 and 2234 allege underpayment of royalties seek recovery of $29 in underpaid royalties and related interests. The Company objects to the CLO’s claims on several grounds, including: (1) claims fail to take into account differences in the specific lease language and applicable regulations as they have changed over time; (2) the CLO’s construction of the leases and the regulations are improper; (3) the claims are based upon improper benchmark prices; (4) the claims improperly include amounts for interests; (5) the CLO seeks to impose liability on the Company for royalties where it is not CLO’s lessee; and (6) the claims are barred in whole or in part by the applicable Statute of Limitations and/or the doctrines of laches and estoppel. Pursuant to the Reorganization Plan, if the CLO ultimately prevails on the merits of its claims, any liability arising under the judgment or settlement would be satisfied through the issuance of stock in the Company. Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. (the “ West case”) 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, 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 alleged that certain oil and gas operations conducted by us and the other defendants have induced earthquakes in the Class Area. The plaintiffs did not seek damages for property damage, but instead asked the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through the time at which the court determines there is no longer a risk of induced earthquakes, as well as attorney fees and costs and other relief. 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. On April 14, 2016, we filed a motion to dismiss the claims asserted against us for failure to state a claim upon which relief can be granted. 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. Other defendants filed motions to dismiss the action which were granted on May 12, 2017. On July 18, 2017, plaintiffs filed a Second Amended Complaint adding additional named plaintiffs as putative class representatives and adding three additional counties to the putative class area. In the Second Amended Complaint, plaintiffs sought damages for nuisance, negligence, abnormally dangerous activities, and trespass. Due to Chaparral’s bankruptcy, plaintiffs specifically limited alleged damages related to Chaparral’s disposal activities occurring after our emergence from bankruptcy on March 21, 2017. We moved to dismiss the Second Amended Complaint on September 15, 2017. On August 13, 2018, the court granted our motion to dismiss, and on August 16, 2018 issued an order striking the class allegations from the Second Amended Complaint. On August 30, 2018, plaintiffs filed a motion for a permissive appeal with the Tenth Circuit, challenging the order dismissing the class allegations. The Tenth Circuit denied plaintiffs’ petition for leave to appeal on September 24, 2018. Because the plaintiffs still have live claims pending against other defendants, the district court’s dismissal of the claims asserted against us are not yet final. In the event plaintiffs ultimately seek to appeal our dismissal, we will 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 vigorously defend the case. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. We filed an objection to class treatment of the proof of claim filed by the West plaintiffs in our bankruptcy proceeding. The Bankruptcy Court heard our objection, and on February 9, 2018 granted our objection to class treatment of the proof of claim. James Butler et al. v. Berexco, L.L.C., Chaparral Energy, L.L.C, et al. (the " Butler case") On October 13, 2017, a group of fifty-two individual plaintiffs filed a lawsuit in the District Court of Payne County, State of Oklahoma against twenty-six named defendants, including us, and twenty-five unnamed defendants. Plaintiffs are all property owners and residents of Payne County, Oklahoma, and allege salt water disposal activities by the defendants, owners or operators of salt water disposal wells, induced earthquakes which have caused damage to real and personal property, and emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, trespass, and ask for compensatory and punitive damages. On December 18, 2017, we moved the court to dismiss the claims against us. Prior to plaintiffs responding to our motion, a hearing on a motion to stay the Butler case was held on January 4, 2018. The judge granted the motion to stay proceedings, ruling that the Butler case was stayed pending final judgment or denial of class certification in the West case. Despite the dismissal of the class allegations in the West case, the stay has not been lifted. Our motion to dismiss will not be considered until the stay is lifted, at which time, if necessary, we will dispute plaintiffs’ claims, dispute that the remedies requested are available under Oklahoma law, and vigorously defend the case. Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al. On March 26, 2018, a group of twenty-seven individual plaintiffs filed a lawsuit in the District Court of Logan County, State of Oklahoma against twenty-three named defendants, including us, and twenty-five unnamed defendants. Plaintiffs are all property owners and residents of Logan County, Oklahoma, and allege the defendants, all oil and gas companies which have engaged in injection well operations, induced earthquakes which have caused damage to real and personal property, and caused emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, and trespass, and ask for compensatory and punitive damages, and attorney fees and costs. On October 22, 2018, we filed a motion to dismiss the claims asserted against us for failure to state a claim upon which relief can be granted. Jointly with other defendants, we have also filed a motion to stay the proceedings pending resolution of the West case. Despite dismissal of the class allegations in the West case, the stay has not been lifted. When the stay is lifted, we will dispute the plaintiffs’ claims, dispute the remedies requested are available under Oklahoma law, and vigorously defend the case. Hallco Petroleum, Inc. v. Chaparral Energy, L.L.C. On November 7, 2017, Hallco Production, LLC (“Hallco”) filed a lawsuit against us in the District Court of Kay County, State of Oklahoma. Plaintiffs alleged carbon dioxide which was injected for enhanced oil recovery in wells operated by us in the North Burbank Unit migrated to wells operated by Hallco, damaging its salt water disposal well and therefore preventing operation of, and production from, all wells on Hallco’s lease. Plaintiffs allege the migration of carbon dioxide constituted trespass, and further allege negligence and nuisance. Plaintiff seeks actual damages in excess of $75 , plus punitive damages in an unspecified amount. Because we sold the EOR wells on November 17, 2017, Hallco filed an amended petition on March 6, 2018 to add the purchaser, Perdure Petroleum, LLC, as an additional defendant in the lawsuit. Plaintiff claims the damage is ongoing. We dispute the plaintiff’s claims, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case. Brown & Borelli, Inc. v. Chesapeake Operating, L.L.C. et al. , in the District Court of Kingfisher County, State of Oklahoma. The plaintiff filed its petition in this case on August 24, 2018. In the petition, the plaintiff alleges our use of hydraulic fracturing during completion of a certain horizontal oil and gas well caused damage to plaintiff’s existing vertical wells located in another section. The plaintiff also alleges two co-defendants’ completion of horizontal wells likewise caused damage to the same vertical wells. Plaintiff asserts claims for trespass and nuisance against all defendants and seeks to recover compensatory damages for the alleged loss of production to plaintiff’s vertical wells. We filed an answer on October 9, 2018 disputing plaintiff’s material allegations and asserting certain affirmative and other defenses. Discovery is ongoing and no scheduling order has yet been entered by the court. We will vigorously defend 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, quiet title actions, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. These proceedings may include allegations of damages from induced earthquakes, which we will vigorously defend as necessary. 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. Contractual obligations We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, financing leases and purchase obligations. Our operating leases include leases for drilling rigs, which have terms of up to 15 months , and leases on CO 2 recycle compressors, which have terms of seven years . Aside from operating leases, we also have financing leases for our CO 2 recycle compressors and fleet vehicles. In conjunction with the sale of our EOR assets, all our leased CO 2 compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank, the originating lessor. The subleases are structured such that the lease payments and remaining lease term are identical to the original leases. Other than additional borrowings under our Credit Facility and our new leases for fleet vehicles (see Note 5—Leases), we did not have material changes to our contractual commitments since December 31, 2018.

Nature of operations and summ_2

Nature of operations and summary of significant accounting policies (Policies)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Nature of operations	Nature of operations Chaparral Energy, Inc. and its subsidiaries (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and our commodity products include crude oil, natural gas and natural gas liquids.
Interim financial statements	Interim financial statements The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018 , as amended. The financial information as of March 31, 2019 , and for the three months ended March 31, 2019 and 2018 , is unaudited. The financial information as of December 31, 2018 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2018 . In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2019 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2019 . 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 maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of March 31, 2019 , cash with a recorded balance totaling approximately $9,127 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.
Accounts receivable	Accounts receivable We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized.
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. Costs associated with unevaluated oil and natural gas properties are excluded from the amortizable base until a determination has been made as to the existence of proved reserves. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well upon proving up reserves of a successful well or upon determination of a dry or uneconomic well under a process that is conducted each quarter. Furthermore, unevaluated oil and natural gas properties are reviewed for impairment if events and circumstances exist that indicate a possible decline in the recoverability of the carrying amount of such property. The impairment assessment is conducted at least once annually and whenever there are indicators that impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves. In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of the application of fresh start accounting on the Effective Date, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play. Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. Our estimates of oil and natural gas reserves as of March 31, 2019 , and the related PV-10 value, were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC. We recorded a ceiling test write-down to our oil and natural gas properties of $49,722 for the three months ended March 31, 2019. We recorded no impairments for the three months ended March 31, 2018. The 2019 loss is reflected in “Impairment of oil and gas assets” in our consolidated statements of operations. Producer imbalances. We account for natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at March 31, 2019 , and December 31, 2018 , were immaterial.
Revenue recognition	Please see “Note 16—Revenue recognition” in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2018 , for a discussion of our revenue recognition policy including a description of products and revenue disaggregation criteria, performance obligations, pricing , measurement and contract assets and liabilities. Revenue recognition In May 2014, the Financial Accounting Standards Board ("FASB") issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”). ASC 606 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.
Income taxes	Income taxes The provision for income taxes is based on a current estimate of the annual effective income tax rate adjusted to reflect the impact of permanent differences and discrete items. Significant management judgment is required in estimating operating income in order to determine our effective income tax rate. Our effective income tax rate was 0% and 0% for the three months ended March 31, 2019 and 2018, respectively. The consistent effective tax rate for the three months ended March 31, 2019 is a result of maintaining a valuation allowance against substantially all of our net deferred tax asset. Despite the Company’s net loss for the three month period ended March 31, 2019, we did no t record any net deferred tax benefit, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. 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 our 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 our net deferred tax asset is necessary, we likely will not have any additional deferred income tax expense or benefit. The benefit of an uncertain tax position taken, or expected to be taken, on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at March 31, 2019, or December 31, 2018. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of Internal Revenue Code of 1986, as amended ("IRC") Section 382 on March 21, 2017. This ownership change subjected certain of the Company’s tax attributes, including $760,067 of federal net operating loss carryforwards, to an IRC Section 382 limitation. This limitation has not resulted in a current tax liability for the three month period ended March 31, 2019, or any intervening period since March 21, 2017.
Restructuring	Restructuring . We previously incurred exit costs in conjunction with our EOR asset divestiture, which are predominantly comprised of one-time severance and termination benefits for the affected employees. The expense recorded in 2018 is a result of termination benefits for the final slate of employees terminated as a result of the divestiture.
Subleases	Subleases . Our subleases are comprised of CO 2 compressors that were previously utilized in our EOR operations and leased as both financing and operating leases from U.S. Bank but are now subleased to the purchaser of our EOR assets (the “Sublessee”). Minimum payments under the subleases are equal to the original leases and as such we did not record any losses upon initiation of the subleases. Prior to the asset sale, the financing leases were included in our full cost amortization base and hence subject to amortization on a units-of-production basis, while also incurring interest expense. The payments under our operating leases were previously recorded as “Lease operating” expense on our statement of operations. Based on the facts and circumstances relating to our original leases and the current subleases, we determined that all the subleases were to be classified as operating leases from a lessor’s standpoint. Subsequent to the execution of the subleases in November 2017, all payments received from the Sublessee are reflected as “Sublease revenue” on our statement of operations. Minimum payments we make to U.S. Bank on the original operating leases are reflected as “Other” expense on our statement of operations. With respect to the financing leases, upon executing the subleases, we reclassified the amount associated with these leases from the full cost amortization base to “Property and equipment, net” on our balance sheet and have amortized the asset on a straight line basis prospectively. We will continue incurring interest expense on the financing leases. Please see “Note 5— Leases” for our disclosure on leases.
Reorganization items	Reorganization items Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy in March 2017, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. “Professional fees” in the table below for periods subsequent to the emergence from bankruptcy are comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed.
Recently adopted and Recently issued accounting pronouncements	Recently adopted accounting pronouncements In February 2016, the FASB issued authoritative guidance that supersedes previous lease recognition requirements and requires entities to recognize leases on-balance sheet and disclose key information about leasing arrangements. Please see “Note 5—Leases” for our disclosure regarding adoption of this update. Recently issued accounting pronouncements 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 to offset potential losses 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.

Nature of operations and summ_3

Nature of operations and summary of significant accounting policies (Tables)	3 Months Ended
	Mar. 31, 2019
Accounting Policies [Abstract]
Components of accounts receivable	Accounts receivable consisted of the following: March 31, December 31, Joint interests $ 37,640 $ 31,573 Accrued commodity sales 23,165 30,287 Derivative settlements 1,056 2,092 Other 1,793 3,375 Allowance for doubtful accounts (1,002 ) (1,240 ) $ 62,652 $ 66,087
Components of inventory	Inventories consisted of the following: March 31, December 31, Equipment inventory $ 3,570 $ 3,663 Commodities 531 574 Inventory valuation allowance (178 ) (178 ) $ 3,923 $ 4,059
Property and equipment	Major classes of property and equipment are shown in the following table: March 31, December 31, Furniture and fixtures $ 520 $ 520 Automobiles and trucks 4,333 3,548 Machinery and equipment 21,714 21,482 Office and computer equipment 6,417 6,183 Building and improvements 18,738 18,693 51,722 50,426 Less accumulated depreciation and amortization 14,283 12,449 37,439 37,977 Land 5,119 5,119 $ 42,558 $ 43,096
Components of unevaluated oil and natural gas properties	The costs of unevaluated oil and natural gas properties consisted of the following: March 31, December 31, Leasehold acreage $ 419,413 $ 427,206 Capitalized interest 13,938 11,377 Wells and facilities in progress of completion 50,670 28,033 Total unevaluated oil and natural gas properties excluded from amortization $ 484,021 $ 466,616
Disaggregation of revenue	The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported: Three months ended March 31, 2019 2018 Revenues: Oil $ 32,802 $ 43,050 Natural gas 11,206 8,736 Natural gas liquids 9,217 9,591 Gross commodity sales 53,225 61,377 Transportation and processing (4,606 ) (3,488 ) Net commodity sales $ 48,619 $ 57,889
Other expense	Other expense consisted of the following: Three months ended March 31, 2019 2018 Restructuring $ — $ 425 Subleases 403 403 Total other expense $ 403 $ 828
Schedule of reorganization items	Reorganization items are as follows: Three months ended March 31, 2019 2018 Loss (gain) on the settlement of liabilities subject to compromise $ — $ 48 Professional fees 463 989 Total reorganization items $ 463 $ 1,037

Earnings per share (Tables)

Earnings per share (Tables)	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Schedule of Basic and Diluted Earnings Per Share	A reconciliation of the components of basic and diluted EPS is presented below: Three months ended March 31, (in thousands, except share and per share data) 2019 2018 Numerator for basic and diluted earnings per share Net loss $ (103,540 ) $ (11,442 ) Denominator for basic earnings per share Weighted average common shares - Basic for Class A and Class B (1) 45,456,214 45,143,297 Denominator for diluted earnings per share Weighted average common shares - Diluted for Class A and Class B (1) 45,456,214 45,143,297 Earnings per share Basic for Class A and Class B (1) $ (2.28 ) $ (0.25 ) Diluted for Class A and Class B (1) $ (2.28 ) $ (0.25 ) Participating securities excluded from earnings per share calculations Warrants (2) — 140,023 Unvested restricted stock awards 886,482 1,589,332 ________________________________ (1) Effective December 19, 2018, all our outstanding Class B shares were converted to Class A shares and subsequently, all our outstanding common stock was comprised only of Class A common stock. Earnings per share for the three months ended March 31, 2018 reflects earnings per share for Class A and Class B common stock in aggregate whereas earnings per share for the three months ended March 31, 2019 reflects earnings per share for Class A common stock. (2) The warrants to purchase shares of our Class A common stock are antidilutive for three months ended March 31, 2018, due to the exercise price exceeding the average price of our Class A shares and due to the net loss we incurred. These warrants expired on June 30, 2018.

Supplemental disclosures to t_2

Supplemental disclosures to the consolidated statements of cash flows (Tables)	3 Months Ended
	Mar. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Supplemental disclosures to the consolidated statements of cash flows	Three months ended March 31, 2019 2018 Net cash provided by operating activities included: Cash payments for interest $ 14,681 $ 2,206 Interest capitalized (3,492 ) (1,521 ) Cash payments for reorganization items 394 410 Non-cash investing activities included: Asset retirement obligation additions and revisions 76 213 Leasing right of use asset additions (see Note 5 - Leases) 670 — Change in accrued oil and gas capital expenditures 15,174 705

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Components of debt	As of the dates indicated, long-term debt and financing leases consisted of the following: March 31, December 31, 8.75% Senior Notes due 2023 $ 300,000 $ 300,000 Credit Facility 30,000 — Real estate mortgage note 8,433 8,588 Installment note payable 337 354 Financing lease obligations 11,648 11,677 Unamortized debt issuance costs (12,366 ) (13,148 ) Total debt, net 338,052 307,471 Less current portion 11,854 12,371 Total long-term debt, net $ 326,198 $ 295,100

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Leases as presented on balance sheet	Our operating lease and financing lease assets and liabilities are recorded on our balance sheet as of March 31, 2019 as follows: As of March 31, 2019 Operating leases Financing leases Right of use asset: Right of use assets from operating leases $ 12,064 $ — Plant, property and equipment, net (1) — 11,488 Total lease assets $ 12,064 $ 11,488 Lease liability: Account payable and accrued liabilities $ 9,757 $ — Long-term debt and financing leases, classified as current — 11,152 Long-term debt and financing leases, less current maturities — 496 Noncurrent operating lease obligations 2,307 — Total lease liabilities $ 12,064 $ 11,648 ________________________________ (1) CO 2 compressors included in Machinery and equipment and fleet vehicles included in automobiles and trucks. See “Note 1—Nature of operations and summary of significant accounting policies.”
Cost of leases	Our income, expenses and cash flows related to our leases is as follows for the three months ended March 31, 2019 : Three months ended March 31, 2019 Lease cost Finance lease cost: Amortization of right-of-use assets $ 693 Interest on lease liabilities 113 Operating lease cost 308 Short-term lease cost 129 Variable lease cost 95 Sublease income (1,198 ) Total lease cost $ 140 Capitalized operating lease cost (1) $ 3,335 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases (113 ) Operating cash flows from operating leases (308 ) Investing cash flows for operating leases (1,023 ) Financing cash flows for finance leases (699 ) Right-of-use assets obtained in exchange for new finance lease liabilities 670 Weighted-average remaining lease term - finance leases 0.8 years Weighted-average remaining lease term - operating leases 1.3 years Weighted-average discount rate - finance leases 3.96 % Weighted-average discount rate - operating leases 13.22 % ________________________________ (1) The operating lease cost are related to drilling rigs and are capitalized as part of oil and natural gas properties on our balance sheets.
Operating lease maturities	Our lease payments for each of the next five years and thereafter are as follows: As of March 31, 2019 As of December 31, 2018 (1) Operating leases Financing leases Operating leases Financing leases 2019 $ 10,282 $ 11,366 $ 13,890 $ 12,332 2020 1,233 178 1,330 — 2021 1,292 178 1,297 — 2022 274 178 278 — 2023 205 21 205 — Thereafter — — — — Total minimum lease payments 13,286 11,921 17,000 12,332 Less: imputed interest 1,222 273 * * Total lease liability 12,064 11,648 * * Less: current maturities of lease obligations 9,757 11,152 * * Long-term lease obligations $ 2,307 $ 496 * * ________________________________ (1) Represents undiscounted firm commitments as of December 31, 2018 * Disclosure not required under ASC 840.
Finance lease maturities	Our lease payments for each of the next five years and thereafter are as follows: As of March 31, 2019 As of December 31, 2018 (1) Operating leases Financing leases Operating leases Financing leases 2019 $ 10,282 $ 11,366 $ 13,890 $ 12,332 2020 1,233 178 1,330 — 2021 1,292 178 1,297 — 2022 274 178 278 — 2023 205 21 205 — Thereafter — — — — Total minimum lease payments 13,286 11,921 17,000 12,332 Less: imputed interest 1,222 273 * * Total lease liability 12,064 11,648 * * Less: current maturities of lease obligations 9,757 11,152 * * Long-term lease obligations $ 2,307 $ 496 * * ________________________________ (1) Represents undiscounted firm commitments as of December 31, 2018 * Disclosure not required under ASC 840.
Schedule of changes from accounting pronouncement	In accordance with ASC 842, the disclosure of the impact of adoption on our balance statement is as follows: As of January 1, 2019 Balances upon adoption Balances without adoption of ASC 842 Effect of change Assets Right of use asset from operating leases, net $ 14,999 $ — $ 14,999 Liabilities Accounts payable and accrued liabilities 12,467 — 12,467 Noncurrent operating lease obligation 2,532 — 2,532

Derivative instruments (Tables)

Derivative instruments (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of derivatives outstanding	The following table summarizes our crude oil derivatives outstanding as of March 31, 2019 : Period and type of contract Volume MBbls Weighted average fixed price per Bbl 2019 Oil swaps 1,935 $ 56.06 Oil roll swaps 380 $ 0.49 2020 Oil swaps 2,007 $ 50.56 Oil roll swaps 410 $ 0.38 2021 Oil swaps 690 $ 46.24 Oil roll swaps 150 $ 0.30 The following table summarizes our natural gas derivatives outstanding as of March 31, 2019 : Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2019 Natural gas swaps 11,713 $ 2.85 Natural gas basis swaps 8,882 $ (0.61 ) 2020 Natural gas swaps 6,000 $ 2.75 Natural gas basis swaps 3,600 $ (0.46 ) The following table summarizes our natural gas liquid derivatives outstanding as of March 31, 2019 : Period and type of contract Volume Thousands of Gallons Weighted average fixed price per gallon 2019 Natural gasoline swaps 3,570 $ 1.39 Propane swaps 8,232 $ 0.74 2020 Natural gasoline swaps 1,890 $ 1.39 Propane swaps 4,284 $ 0.74 Subsequent to March 31, 2019 and through May 7, 2019, we entered into additional derivative contracts, including 195 MBbls of crude oil collars scheduled to settle in 2020 with a weighted average purchased put price of $55.00 per barrel and sold call of $66.42 per barrel, and the following natural gas liquids contracts: Period and type of contract Volume Thousands of Gallons Weighted average fixed price per Gallon 2019 Iso butane 1,344 $ 0.72 Natural gasoline 1,848 $ 1.24 N-butane 3,822 $ 0.70 Propane 3,864 $ 0.64 2020 Iso butane 630 $ 0.72 Natural gasoline 882 $ 1.24 N-butane 1,722 $ 0.70 Propane 1,890 $ 0.64
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 at March 31, 2019 As at December 31, 2018 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 891 $ (685 ) $ 206 $ 833 $ (488 ) $ 345 Crude oil derivative contracts 1,851 (30,764 ) (28,913 ) 24,208 (4,452 ) 19,756 NGL derivative contracts 1,857 — 1,857 4,581 — 4,581 Total derivative instruments 4,599 (31,449 ) (26,850 ) 29,622 (4,940 ) 24,682 Less: Netting adjustments (1) (4,599 ) 4,599 — (3,398 ) 3,398 — Derivative instruments - current — (10,874 ) (10,874 ) 24,025 — 24,025 Derivative instruments - long-term $ — $ (15,976 ) $ (15,976 ) $ 2,199 $ (1,542 ) $ 657 ________________________________ (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 counterparties are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
Derivative (losses) gains in the consolidated statements of operations	“Derivative (losses) gains” in the consolidated statements of operations are comprised of the following: Three months ended March 31, 2019 2018 Change in fair value of commodity price derivatives $ (51,531 ) $ (12,257 ) Settlements (paid) received on commodity price derivatives 515 (4,244 ) Total derivative losses $ (51,016 ) $ (16,501 )

Fair value measurements (Tables

Fair value measurements (Tables)	3 Months Ended
	Mar. 31, 2019
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 at March 31, 2019 As at December 31, 2018 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 4,598 $ (30,910 ) $ (26,312 ) $ 29,370 $ (4,718 ) $ 24,652 Significant unobservable inputs (Level 3) 1 (539 ) (538 ) 252 (222 ) 30 Netting adjustments (1) (4,599 ) 4,599 — (3,398 ) 3,398 — $ — $ (26,850 ) (26,850 ) $ 26,224 $ (1,542 ) $ 24,682 ________________________________ (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 counterparties 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, were as follows for the periods presented: Three months ended March 31, Net derivative assets (liabilities) 2019 2018 Beginning balance $ 30 $ (295 ) Realized and unrealized (losses) gains included in derivative losses (981 ) (432 ) Settlements paid 413 108 Ending balance $ (538 ) $ (619 ) (Losses) gains relating to instruments still held at the reporting date included in derivative losses for the period $ (537 ) $ (380 )
Fair value of other financial instruments	The carrying value and estimated fair value of our debt were as follows: March 31, 2019 December 31, 2018 Level 2 Carrying value (1) Estimated fair value Carrying value (1) Estimated fair value 8.75% Senior Notes due 2023 $ 300,000 $ 207,183 $ 300,000 $ 213,618 Credit Facility 30,000 30,000 — — Other secured debt 8,770 8,770 8,942 8,942 ________________________________ (1) The carrying value excludes deductions for debt issuance costs.
Offsetting assets and liabilities	The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting assets (liabilities) Net assets (liabilities) Derivatives (1) Amounts outstanding under credit facilities (2) Net amount March 31, 2019 Derivative assets $ 4,599 $ (4,599 ) $ — $ — $ — $ — Derivative liabilities (31,449 ) 4,599 (26,850 ) — — (26,850 ) $ (26,850 ) $ — $ (26,850 ) $ — $ — $ (26,850 ) December 31, 2018 Derivative assets $ 29,622 $ (3,398 ) $ 26,224 $ (1,542 ) $ — $ 24,682 Derivative liabilities (4,940 ) 3,398 (1,542 ) 1,542 — — $ 24,682 $ — $ 24,682 $ — $ — $ 24,682 ________________________________ (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. (2) The amount outstanding under our Credit Facility that is available to offset our net derivative assets due from counterparties that are lenders under our Credit Facility.

Asset retirement obligations (T

Asset retirement obligations (Tables)	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	The following table provides a summary of our asset retirement obligation activity: Balance at January 1, 2019 $ 23,147 Liabilities incurred in current period 66 Liabilities settled or disposed in current period (271 ) Revisions in estimated cash flows 10 Accretion expense 354 Balance at March 31, 2019 $ 23,306 Less current portion included in accounts payable and accrued liabilities 1,058 Asset retirement obligations, long-term $ 22,248

Deferred compensation (Tables)

Deferred compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Share-based Compensation [Abstract]
Summary of amounts related to cash LTIP	A summary of compensation expense for the Cash LTIP is presented below: Three months ended March 31, 2019 2018 Cash LTIP expense (net of amounts capitalized) $ 91 $ 95 Cash LTIP payments — 17
Rollforward of unvested deferred compensation	A summary of our RSU activity is presented below: Stock-settled RSUs Cash-settled RSUs Weighted average award date fair value Restricted units Weighted average award date fair value Restricted units ($ per share) ($ per share) Unvested and outstanding at January 1, 2019 $ 17.66 89,633 $ 17.66 $ 37,196 Granted $ — — $ 6.37 $ 1,570 Forfeited $ 17.66 (2,554 ) $ 17.66 $ (1,136 ) Unvested and outstanding at March 31, 2019 $ 17.66 87,079 $ 17.19 $ 37,630 A summary of our restricted stock activity pursuant to our MIP is presented below: Time Shares Performance Shares Weighted average award date fair value Restricted shares Vest date fair value Weighted average award date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2019 $ 20.06 818,206 $ 20.12 $ 125,528 Granted $ 7.97 78,378 $ 7.97 $ 15,000 Vested $ 20.05 (73,517 ) $ 525 $ — $ — Forfeited $ 20.05 (73,515 ) $ 20.05 $ (23,598 ) Unvested and outstanding at March 31, 2019 $ 18.79 749,552 $ 18.57 $ 116,930
Stock-based compensation cost	Stock-based compensation expense is as follows for the periods indicated: Three months ended March 31, 2019 2018 Stock-based compensation cost $ 1,460 $ 5,580 Less: stock-based compensation cost capitalized (626 ) (957 ) Stock-based compensation expense $ 834 $ 4,623 Number of vested shares repurchased 80,422 — Payments for stock-based compensation $ 463 $ 1,422

Nature of operations and summ_4

Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Cash held	$ 9,127
Components of accounts receivable
Joint interests	37,640	$ 31,573
Accrued commodity sales	23,165	30,287
Derivative settlements	1,056	2,092
Other	1,793	3,375
Allowance for doubtful accounts	(1,002)	(1,240)
Accounts receivable, net	$ 62,652	$ 66,087

Nature of operations and summ_5

Nature of operations and summary of significant accounting policies (Inventories) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Energy Related Inventory
Equipment inventory	$ 3,570	$ 3,663
Commodities	531	574
Inventory valuation allowance	(178)	(178)
Inventories, net	$ 3,923	$ 4,059

Nature of operations and summ_6

Nature of operations and summary of significant accounting policies (Property and Equipment) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	$ 51,722	$ 50,426
Less accumulated depreciation and amortization	14,283	12,449
Property and equipment, excluding land, net	37,439	37,977
Land	5,119	5,119
Property and equipment - at cost, net	42,558	43,096
Furniture and fixtures
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	520	520
Automobiles and trucks
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	4,333	3,548
Machinery and equipment
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	21,714	21,482
Office and computer equipment
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	6,417	6,183
Building and improvements
Property, Plant and Equipment [Line Items]
Property and equipment, excluding land, gross	$ 18,738	$ 18,693

Nature of operations and summ_7

Nature of operations and summary of significant accounting policies (Unevaluated Oil and Natural Gas Properties) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Accounting Policies [Abstract]
Impairment of oil and gas assets	$ 49,722,000	$ 0
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]
Leasehold acreage	419,413,000		$ 427,206,000
Capitalized interest	13,938,000		11,377,000
Wells and facilities in progress of completion	50,670,000		28,033,000
Total unevaluated oil and natural gas properties excluded from amortization	$ 484,021,000		$ 466,616,000

Nature of operations and summ_8

Nature of operations and summary of significant accounting policies (Revenue Recognition) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Gross commodity sales	$ 53,225	$ 61,377
Transportation and processing	(4,606)	(3,488)
Net commodity sales	48,619	57,889
Oil
Disaggregation of Revenue [Line Items]
Gross commodity sales	32,802	43,050
Natural gas
Disaggregation of Revenue [Line Items]
Gross commodity sales	11,206	8,736
Natural gas liquids
Disaggregation of Revenue [Line Items]
Gross commodity sales	$ 9,217	$ 9,591

Nature of operations and summ_9

Nature of operations and summary of significant accounting policies (Income Taxes) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Accounting Policies [Abstract]
Effective tax rate	0.00%	0.00%
Deferred tax benefit	$ 0
Uncertain tax positions	0		$ 0
Net operating loss carryforwards subject to limitation	$ 760,067,000

Nature of operations and sum_10

Nature of operations and summary of significant accounting policies (Other Expense) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Other Income and Expenses [Abstract]
Restructuring	$ 0	$ 425
Subleases	403	403
Total other expense	$ 403	$ 828

Nature of operations and sum_11

Nature of operations and summary of significant accounting policies (Joint Venture) (Details) - Joint Development Agreement $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)	Sep. 25, 2017USD ($)well
Joint Venture [Line Items]
Percentage of working interest in wells		15.00%
Percentage of working interest in wells upon achievement of required internal rate of return		75.00%
Joint venture cost overages recorded | $	$ 3,182
Canadian
Joint Venture [Line Items]
Number of joint venture stack wells | well		17
Garfield
Joint Venture [Line Items]
Number of joint venture stack wells | well		13
Bayou City Energy Management, LLC
Joint Venture [Line Items]
Funded percentage of drilling completion and equipment costs		100.00%
Number of joint venture stack wells | well		30
Percentage of working interest in wells		85.00%
Percentage of internal rate of return		14.00%
Percentage of working interest in wells upon achievement of required internal rate of return		25.00%
Bayou City Energy Management, LLC | Minimum
Joint Venture [Line Items]
Average well cost caps per gross well | $		$ 3,400
Bayou City Energy Management, LLC | Maximum
Joint Venture [Line Items]
Average well cost caps per gross well | $		$ 4,000

Nature of operations and sum_12

Nature of operations and summary of significant accounting policies (Schedule of Reorganization Items) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Accounting Policies [Abstract]
Loss (gain) on the settlement of liabilities subject to compromise	$ 0	$ 48
Professional fees	463	989
Total reorganization items	$ 463	$ 1,037

Earnings per share (Details)

Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
		Mar. 31, 2019	Mar. 31, 2018
Numerator for basic and diluted earnings per share
Net loss		$ (103,540)	$ (11,442)
Denominator for basic earnings per share
Weighted average common shares - Basic for Class A and Class B (in shares)	[1]	45,456,214	45,143,297
Denominator for diluted earnings per share
Weighted average common shares - Diluted for Class A and Class B (in shares)	[1]	45,456,214	45,143,297
Earnings per share
Basic for Class A and Class B (in dollars per share)	[1]	$ (2.28)	$ (0.25)
Diluted for Class A and Class B (in dollars per share)	[1]	$ (2.28)	$ (0.25)
Warrants
Earnings per share
Participating securities excluded from earnings per share calculations (in shares)		0	140,023
Unvested restricted stock awards
Earnings per share
Participating securities excluded from earnings per share calculations (in shares)		886,482	1,589,332
[1]	See “Note 2—Earnings per share.”

Supplemental disclosures to t_3

Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Net cash provided by operating activities included:
Cash payments for interest	$ 14,681	$ 2,206
Interest capitalized	(3,492)	(1,521)
Cash payments for reorganization items	394	410
Non-cash investing activities included:
Asset retirement obligation additions and revisions	76	213
Leasing right of use asset additions (see Note 5 - Leases)	670	0
Change in accrued oil and gas capital expenditures	$ 15,174	$ 705

Debt (Components of Debt) (Deta

Debt (Components of Debt) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
8.75% Senior Notes due 2023	$ 300,000	$ 300,000
Credit Facility	30,000	0
Real estate mortgage note	8,433	8,588
Installment note payable	337	354
Financing lease obligations	11,648	11,677
Unamortized debt issuance costs	(12,366)	(13,148)
Total debt, net	338,052	307,471
Less current portion	11,854	12,371
Total long-term debt, net	$ 326,198	$ 295,100
8.75% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate stated percentage	8.75%

Debt (Credit Facility) (Details

Debt (Credit Facility) (Details)	3 Months Ended
	Mar. 31, 2019USD ($)qtr	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Borrowing base amount	$ 750,000,000
Current borrowing capacity	325,000,000
Outstanding borrowings	30,000,000	$ 0
Availability under the facility	153,956,000
Credit Facility and Letters of Credit Outstanding
Line of Credit Facility [Line Items]
Outstanding borrowings	$ 294,131,000
Credit Facility
Line of Credit Facility [Line Items]
Number of consecutive quarters | qtr	4
Minimum | Credit Facility
Line of Credit Facility [Line Items]
Current Ratio covenant	1
Maximum | Credit Facility
Line of Credit Facility [Line Items]
Ratio of debt to EBITDAX	4
Adjusted LIBO Rate | Credit Facility
Line of Credit Facility [Line Items]
Weighted average interest rate	4.49%

Debt (Senior Notes) (Details)

Debt (Senior Notes) (Details) - 8.75% Senior Notes - USD ($)	Mar. 31, 2019	Jun. 29, 2018
Debt Instrument [Line Items]
Aggregate principal amount		$ 300,000,000
Debt instrument, interest rate	8.75%	8.75%

Leases (Financing Leases) (Deta

Leases (Financing Leases) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Mar. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Financing lease obligations		$ 11,648	$ 11,677
Weighted-average discount rate - finance leases		3.96%
Minimum lease payment		$ 11,921	$ 12,332
CO2 Compressor
Lessee, Lease, Description [Line Items]
Financing lease obligations	$ 24,500
Finance lease, term	84 months
Option to purchase for a specified price, period	72 months
Weighted-average discount rate - finance leases	3.80%
Minimum lease payment	$ 3,181
Fleet Trucks
Lessee, Lease, Description [Line Items]
Financing lease obligations		$ 670
Finance lease, term		48 months

Leases (Operating Leases) (Deta

Leases (Operating Leases) (Details) - drilling_rig	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2016	Dec. 31, 2014
Lessee, Lease, Description [Line Items]
Number of drilling rigs	1	2
CO2 Compressor
Lessee, Lease, Description [Line Items]
Operating lease, term	7 years		84 months	84 months
Drilling Rigs
Lessee, Lease, Description [Line Items]
Operating lease, term	15 months	15 months

Leases (Short Term Leases) (Det

Leases (Short Term Leases) (Details) - drilling_rig	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Number of drilling rigs	1	2
Drilling Rigs
Lessee, Lease, Description [Line Items]
Short term leases, term	4 months
Short term lease, remaining term	1 month
Minimum
Lessee, Lease, Description [Line Items]
Short term leases, term	1 month
Maximum
Lessee, Lease, Description [Line Items]
Short term leases, term	6 months
Maximum | Drilling Rigs
Lessee, Lease, Description [Line Items]
Short term leases, term	6 months

Leases (Balance Sheet Disclosur

Leases (Balance Sheet Disclosures) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating leases
Right of use assets from operating leases	$ 12,064	$ 14,999	$ 0
Accounts payable and accrued liabilities	9,757	12,467
Noncurrent operating lease obligation	2,307	$ 2,532	0
Total lease liabilities	12,064
Lessee, Finance Lease, Description [Abstract]
Plant, property and equipment, net	11,488
Long-term debt and financing leases, classified as current	11,152
Long-term debt and financing leases, less current maturities	496
Total lease liabilities	$ 11,648		$ 11,677

Leases (Lease Cost) (Details)

Leases (Lease Cost) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Finance lease cost:
Amortization of right-of-use assets	$ 693
Interest on lease liabilities	113
Operating lease cost	308
Short-term lease cost	129
Variable lease cost	95
Sublease income	(1,198)	$ (1,198)
Total lease cost	140
Capitalized operating lease cost	3,335
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases	(113)
Operating cash flows from operating leases	(308)
Investing cash flows for operating leases	(1,023)
Financing cash flows for finance leases	(699)
Right-of-use assets obtained in exchange for new finance lease liabilities	$ 670
Weighted-average remaining lease term - finance leases	9 months 12 days
Weighted-average remaining lease term - operating leases	1 year 3 months 24 days
Weighted-average discount rate - finance leases	3.96%
Weighted-average discount rate - operating leases	13.22%

Leases (Lease Assets and Liabil

Leases (Lease Assets and Liabilities, Additional Information) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)
Leases [Abstract]
Rent expense	$ 968

Leases (Maturity Schedule) (Det

Leases (Maturity Schedule) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Operating leases
2019	$ 10,282
2019			$ 13,890
2020	1,233		1,330
2021	1,292		1,297
2022	274		278
2023	205		205
Thereafter	0		0
Total minimum lease payments	13,286		17,000
Less: imputed interest	1,222
Total lease liabilities	12,064
Less: current maturities of lease obligations	9,757	$ 12,467
Long-term lease obligations	2,307	$ 2,532	0
Financing leases
2019	11,366
2019			12,332
2020	178		0
2021	178		0
2022	178		0
2023	21		0
Thereafter	0		0
Total minimum lease payments	11,921		12,332
Less: imputed interest	273
Total lease liabilities	11,648		$ 11,677
Less: current maturities of lease obligations	11,152
Long-term lease obligations	$ 496

Leases (Impact of Adoption) (De

Leases (Impact of Adoption) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right of use assets from operating leases	$ 12,064	$ 14,999	$ 0
Accounts payable and accrued liabilities	9,757	12,467
Noncurrent operating lease obligation	$ 2,307	2,532	$ 0
Effect of change
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right of use assets from operating leases		14,999
Accounts payable and accrued liabilities		12,467
Noncurrent operating lease obligation		$ 2,532

Derivative instruments (Summary

Derivative instruments (Summary of Derivatives Outstanding) (Details)	May 07, 2019MBblsgal$ / bbl$ / gal	Mar. 31, 2019BritishThermalUnitsgalbbl$ / BTU$ / bbl$ / gal
Oil swaps | Derivative Maturing In 2019 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		1,935
Weighted average fixed price (usd per unit) | $ / bbl		56.06
Oil swaps | Derivative Maturing In 2020 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		2,007
Weighted average fixed price (usd per unit) | $ / bbl		50.56
Oil swaps | Derivative Maturing In 2021 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		690
Weighted average fixed price (usd per unit) | $ / bbl		46.24
Oil roll swaps | Derivative Maturing In 2019 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		380
Weighted average fixed price (usd per unit) | $ / bbl		0.49
Oil roll swaps | Derivative Maturing In 2020 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		410
Weighted average fixed price (usd per unit) | $ / bbl		0.38
Oil roll swaps | Derivative Maturing In 2021 | Crude oil derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | bbl		150
Weighted average fixed price (usd per unit) | $ / bbl		0.30
Natural gas swaps | Derivative Maturing In 2019 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | BritishThermalUnits		11,713
Weighted average fixed price (usd per unit) | $ / BTU		2.85
Natural gas swaps | Derivative Maturing In 2020 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | BritishThermalUnits		6,000
Weighted average fixed price (usd per unit) | $ / BTU		2.75
Natural gas basis swaps | Derivative Maturing In 2019 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | BritishThermalUnits		8,882
Weighted average fixed price (usd per unit) | $ / BTU		0.61
Natural gas basis swaps | Derivative Maturing In 2020 | Natural gas derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | BritishThermalUnits		3,600
Weighted average fixed price (usd per unit) | $ / BTU		0.46
Natural gasoline swaps | Derivative Maturing In 2019 | Natural gas liquid derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal		3,570
Weighted average fixed price (usd per unit) | $ / gal		1.39
Natural gasoline swaps | Derivative Maturing In 2020 | Natural gas liquid derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal		1,890
Weighted average fixed price (usd per unit) | $ / gal		1.39
Propane swaps | Derivative Maturing In 2019 | Natural gas liquid derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal		8,232
Weighted average fixed price (usd per unit) | $ / gal		0.74
Propane swaps | Derivative Maturing In 2020 | Natural gas liquid derivatives
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal		4,284
Weighted average fixed price (usd per unit) | $ / gal		0.74
Crude oil collars | Derivative Maturing In 2020 | Crude oil derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | MBbls	195
Weighted average purchased put price (in dollars per barrel) | $ / bbl	55
Sold call price (in dollars per barrel) | $ / bbl	66.42
Iso butane | Derivative Maturing In 2019 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	1,344
Weighted average fixed price (usd per unit) | $ / gal	0.72
Iso butane | Derivative Maturing In 2020 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	630
Weighted average fixed price (usd per unit) | $ / gal	0.72
Natural gasoline | Derivative Maturing In 2019 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	1,848
Weighted average fixed price (usd per unit) | $ / gal	1.24
Natural gasoline | Derivative Maturing In 2020 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	882
Weighted average fixed price (usd per unit) | $ / gal	1.24
N-butane | Derivative Maturing In 2019 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	3,822
Weighted average fixed price (usd per unit) | $ / gal	0.70
N-butane | Derivative Maturing In 2020 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	1,722
Weighted average fixed price (usd per unit) | $ / gal	0.70
Propane | Derivative Maturing In 2019 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	3,864
Weighted average fixed price (usd per unit) | $ / gal	0.64
Propane | Derivative Maturing In 2020 | Natural gas liquid derivatives | Subsequent Event
Derivative [Line Items]
Volume (in MBbl, BBtu, or Gallon) | gal	1,890
Weighted average fixed price (usd per unit) | $ / gal	0.64

Derivative instruments (Balance

Derivative instruments (Balance Sheet at Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair value of derivative instruments
Derivative assets, gross	$ 4,599	$ 29,622
Derivative liabilities, gross	(31,449)	(4,940)
Derivative assets (liabilities), net	(26,850)	24,682
Derivative assets, netting adjustments	(4,599)	(3,398)
Derivative liabilities, netting adjustments	4,599	3,398
Current derivative assets, net	0	24,025
Current derivative liabilities, net	(10,874)	0
Current derivative assets (liabilities), net	(10,874)	24,025
Long-term derivative assets, net	0	2,199
Long-term derivative liabilities, net	(15,976)	(1,542)
Long-term derivative assets (liabilities), net	(15,976)	657
Natural gas derivative contracts
Fair value of derivative instruments
Derivative assets, gross	891	833
Derivative liabilities, gross	(685)	(488)
Derivative assets (liabilities), net	206	345
Crude oil derivative contracts
Fair value of derivative instruments
Derivative assets, gross	1,851	24,208
Derivative liabilities, gross	(30,764)	(4,452)
Derivative assets (liabilities), net	(28,913)	19,756
NGL derivative contracts
Fair value of derivative instruments
Derivative assets, gross	1,857	4,581
Derivative liabilities, gross	0	0
Derivative assets (liabilities), net	$ 1,857	$ 4,581

Derivative instruments (Derivat

Derivative instruments (Derivative (Losses) Gains in the Consolidated Statements of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of commodity price derivatives	$ (51,531)	$ (12,257)
Settlements (paid) received on commodity price derivatives	515	(4,244)
Total derivative losses	$ (51,016)	$ (16,501)

Fair value measurements (Recurr

Fair value measurements (Recurring) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets, gross	$ 4,599	$ 29,622
Derivative liabilities, gross	(31,449)	(4,940)
Derivative assets (liabilities), net	(26,850)	24,682
Derivative assets, amount offset	(4,599)	(3,398)
Derivative liabilities, amounts offset	4,599	3,398
Derivative assets, net	0	26,224
Derivative liabilities, net	(26,850)	(1,542)
Recurring Fair Value Measurements
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis
Derivative assets (liabilities), net	(26,850)	24,682
Derivative assets, amount offset	(4,599)	(3,398)
Derivative liabilities, amounts offset	4,599	3,398
Derivative assets amount offset (liabilities), net	0	0
Derivative assets, net	0	26,224
Derivative liabilities, net	(26,850)	(1,542)
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	4,598	29,370
Derivative liabilities, gross	(30,910)	(4,718)
Derivative assets (liabilities), net	(26,312)	24,652
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	1	252
Derivative liabilities, gross	(539)	(222)
Derivative assets (liabilities), net	$ (538)	$ 30

Fair value measurements (Level

Fair value measurements (Level 3 Rollforward) (Details) - Recurring Fair Value Measurements - Significant Unobservable Inputs (Level 3) - Derivative - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Level 3 Rollforward
Beginning balance	$ 30	$ (295)
Realized and unrealized (losses) gains included in derivative losses	(981)	(432)
Settlements paid	413	108
Ending balance	(538)	(619)
(Losses) gains relating to instruments still held at the reporting date included in derivative losses for the period	$ (537)	$ (380)

Fair value measurements (Nonrec

Fair value measurements (Nonrecurring) (Details) - Significant Unobservable Inputs (Level 3) - Nonrecurring Fair Value Measurements	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Nonrecurring Fair Value Measurements
Annual inflation rate	2.25%	2.26%
Risk Free Rate of Return
Nonrecurring Fair Value Measurements
Credit-adjusted risk-free interest rate	0.1235	0.0692

Fair value measurements (Other

Fair value measurements (Other Financial Instruments) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Jun. 29, 2018
8.75% Senior Notes due 2023
Fair Value of Other Financial Instruments
Debt instrument, interest rate	8.75%		8.75%
Significant Other Observable Inputs (Level 2) | Senior Notes | 8.75% Senior Notes due 2023 | Carrying Value
Fair Value of Other Financial Instruments
Debt	$ 300,000	$ 300,000
Significant Other Observable Inputs (Level 2) | Senior Notes | 8.75% Senior Notes due 2023 | Estimated Fair Value
Fair Value of Other Financial Instruments
Debt	207,183	213,618
Significant Other Observable Inputs (Level 2) | Credit Facility | Carrying Value
Fair Value of Other Financial Instruments
Debt	30,000	0
Significant Other Observable Inputs (Level 2) | Credit Facility | Estimated Fair Value
Fair Value of Other Financial Instruments
Debt	30,000	0
Significant Other Observable Inputs (Level 2) | Secured Debt | Carrying Value
Fair Value of Other Financial Instruments
Debt	8,770	8,942
Significant Other Observable Inputs (Level 2) | Secured Debt | Estimated Fair Value
Fair Value of Other Financial Instruments
Debt	$ 8,770	$ 8,942

Fair value measurements (Counte

Fair value measurements (Counterparty Credit Risk) (Details)	Mar. 31, 2019financial_institutions
Concentration of Counterparty Credit Risk
Counterparty Credit Risk
Derivative contracts, number of counterparties	8

Fair value measurements (Deriva

Fair value measurements (Derivatives Offset in Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Derivative assets, gross	$ 4,599	$ 29,622
Derivative assets, amount offset	(4,599)	(3,398)
Derivative assets	0	26,224
Derivative assets, not offset	0	(1,542)
Credit facility balance available to offset net derivative assets	0	0
Derivative asset, net	0	24,682
Derivative liabilities, gross	(31,449)	(4,940)
Derivative liabilities	(26,850)	(1,542)
Derivative liabilities, not offset	0	1,542
Credit facility balance available to offset net derivative liabilities	0	0
Derivative liability, net	(26,850)	0
Derivative asset (liability), gross	(26,850)	24,682
Derivative asset (liability), amount offset	0	0
Derivative asset (liability), net	(26,850)	24,682
Derivative asset (liability) not offset	0	0
Derivative asset (liability), net	$ (26,850)	$ 24,682

Asset retirement obligations (D

Asset retirement obligations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 23,147
Liabilities incurred in current period	66
Liabilities settled or disposed in current period	(271)
Revisions in estimated cash flows	10
Accretion expense	354
Ending balance	23,306
Less current portion included in accounts payable and accrued liabilities	1,058
Asset retirement obligations, long-term	$ 22,248	$ 22,090

Deferred compensation (Cash Inc

Deferred compensation (Cash Incentive Plan) (Details) - Cash LTIP - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Vesting period	4 years
Cash LTIP expense (net of amounts capitalized)	$ 91	$ 95
Cash LTIP payments	0	$ 17
Outstanding liability accrued	$ 1,487

Deferred compensation (2017 Man

Deferred compensation (2017 Management Incentive Plan) (Details) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)tranche$ / sharesshares	Dec. 31, 2018$ / shares	Dec. 31, 2017$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock par value (in dollars per share)	$ 0.01	$ 0.01
Risk free rate	2.52%
Volatility rate	64.10%
Fair value (in dollars per share)	$ 4.66
Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock par value (in dollars per share)			$ 0.01
2017 Management Incentive Plan | Time Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (in years)	3 years
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share)	$ 20.06
Granted (in dollars per share)	7.97
Vested (in dollars per share)	20.05
Forfeited (in dollars per share)	20.05
Unvested and outstanding at end of period (in dollars per share)	$ 18.79
Number of shares
Unvested and outstanding at beginning of period (in shares) | shares	818,206
Granted (in shares) | shares	78,378
Vested (in shares) | shares	(73,517)
Forfeited (in shares) | shares	(73,515)
Unvested and outstanding at end of period (in shares) | shares	749,552
Vest date fair value | $	$ 525
2017 Management Incentive Plan | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of tranches | tranche	3
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share)	$ 20.12
Granted (in dollars per share)	7.97
Vested (in dollars per share)	0
Forfeited (in dollars per share)	20.05
Unvested and outstanding at end of period (in dollars per share)	$ 18.57
Number of shares
Unvested and outstanding at beginning of period (in shares) | shares	125,528
Granted (in shares) | shares	15,000
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(23,598)
Unvested and outstanding at end of period (in shares) | shares	116,930
2017 Management Incentive Plan | Employees | Time Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of comprised shares for granted award	75.00%
2017 Management Incentive Plan | Employees | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of comprised shares for granted award	25.00%
2017 Management Incentive Plan | Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued or reserved for issuance (in shares) | shares			3,388,832

Deferred compensation (2018 Emp

Deferred compensation (2018 Employee LTIP) (Details) - Employee LTIP - RSUs	3 Months Ended
	Mar. 31, 2019$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period (in years)	3 years
Stock-settled RSUs
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 17.66
Granted (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	17.66
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 17.66
Number of shares
Unvested and outstanding at beginning of period (in shares) | shares	89,633
Granted (in shares) | shares	0
Forfeited (in shares) | shares	(2,554)
Unvested and outstanding at end of period (in shares) | shares	87,079
Cash-settled RSUs
Weighted average award date fair value
Unvested and outstanding at beginning of period (in dollars per share) | $ / shares	$ 17.66
Granted (in dollars per share) | $ / shares	6.37
Forfeited (in dollars per share) | $ / shares	17.66
Unvested and outstanding at end of period (in dollars per share) | $ / shares	$ 17.19
Number of shares
Unvested and outstanding at beginning of period (in shares) | shares	37,196
Granted (in shares) | shares	1,570
Forfeited (in shares) | shares	(1,136)
Unvested and outstanding at end of period (in shares) | shares	37,630

Deferred compensation (Companyw

Deferred compensation (Companywide Stock Award) (Details) - New Employee Stock Award Program - shares	1 Months Ended	3 Months Ended
	Jan. 31, 2019	Mar. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares awardable per new employee		100
Granted	700

Deferred compensation (Stock-ba

Deferred compensation (Stock-based Compensation Cost) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation cost	$ 1,460	$ 5,580
Less: stock-based compensation cost capitalized	(626)	(957)
Stock-based compensation expense	$ 834	$ 4,623
Number of vested shares repurchased	80,422	0
Payments for stock-based compensation	$ 463	$ 1,422
Estimated fair value per share at end of period (in dollars per share)	$ 5.70
Aggregate intrinsic value of unvested restricted shares outstanding	$ 5,435
Deferred compensation current	37		$ 17
Unrecognized stock-based compensation cost	$ 4,999
Weighted-average period for unrecognized compensation cost to be recognized	1 year 3 months 3 days

Commitments and Contingencies (

Commitments and Contingencies (Details)	Aug. 24, 2018defendant	Mar. 26, 2018defendantplaintiff	Oct. 13, 2017defendantplaintiff	Apr. 20, 2017USD ($)	Jan. 17, 2017	Aug. 15, 2016USD ($)	Mar. 31, 2019USD ($)claim	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2016	Dec. 31, 2014
Loss Contingencies [Line Items]
Number of claims subject to Bankruptcy Court | claim							100
Drilling Rigs
Loss Contingencies [Line Items]
Operating lease, term							15 months		15 months
CO2 Compressor
Loss Contingencies [Line Items]
Operating lease, term							7 years			84 months	84 months
Naylor Farms Case
Loss Contingencies [Line Items]
Minimum percentage of plaintiff in modified class					60.00%
W.H. Davis Case
Loss Contingencies [Line Items]
Damages sought							$ 17,262,000
W.H. Davis Case | Camrick and North Perryton Units
Loss Contingencies [Line Items]
Percentage of working interest in wells							60.00%
W.H. Davis Case | Camrick and North Perryton Units | W.H. Davis Family Limited Partnership
Loss Contingencies [Line Items]
Percentage of working interest in wells							40.00%
W.H. Davis Case | Farnsworth Unit
Loss Contingencies [Line Items]
Percentage of working interest in wells							100.00%
CLO's Proofs of Claims Nos. 2130 and 2131
Loss Contingencies [Line Items]
Damages sought							$ 1,697,000
CLO's Proof of Claim Nos. 2132, 2133 and 2234
Loss Contingencies [Line Items]
Damages sought							29,000
James Butler et al. v. Berexco, L.L.C.
Loss Contingencies [Line Items]
Number of individual plaintiffs | plaintiff			52
Number of named defendants including parent | defendant			26
Number of unnamed defendants | defendant			25
Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al.
Loss Contingencies [Line Items]
Number of individual plaintiffs | plaintiff		27
Number of named defendants including parent | defendant		23
Number of unnamed defendants | defendant		25
Brown And Borelli, Inc v. Chesapeake Operating, L.L.C.
Loss Contingencies [Line Items]
Number of named defendants including parent | defendant	2
Pending Litigation | Naylor Farms Case Putative Class Action | Minimum
Loss Contingencies [Line Items]
Damages sought						$ 150,000,000	5,000,000
Pending Litigation | Naylor Farms Case Actual and Putative Action | Minimum
Loss Contingencies [Line Items]
Damages sought				$ 90,000,000
Pending Litigation | West Case Putative Class Action | Minimum
Loss Contingencies [Line Items]
Damages sought							75,000,000
Pending Litigation | Hallco Petroleum, Inc. v. Chaparral Energy, L.L.C. | Minimum
Loss Contingencies [Line Items]
Damages sought							75,000
Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding							869,000		$ 869,000
Proceeds from letters							0	$ 0
Cash payments for interest							$ 0	$ 0