Ranger Oil (ROCC) 10-K 28 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 21, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-13283
Entity Registrant Name	PENN VIRGINIA CORP
Entity Incorporation, State or Country Code	VA
Entity Tax Identification Number	23-1184320
Entity Address, Address Line One	16285 Park Ten Place, Suite 500
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77084
City Area Code	713
Local Phone Number	722-6500
Title of 12(b) Security	Common Stock, $0.01 Par Value
Trading Symbol	PVAC
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 412,236,913
Entity Common Stock, Shares Outstanding		15,157,919
Documents Incorporated by Reference	Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0000077159
Current Fiscal Year End Date	--12-31

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues
Gain (Loss) on Disposition of Property Plant Equipment	$ 5	$ (177)	$ (36)
Total revenues	471,216	440,832	160,054
Operating expenses
Lease operating	43,088	35,879	21,784
Cost of Goods and Services Sold	23,197	18,626	10,734
Production and ad valorem taxes	28,057	23,547	8,814
General and administrative	25,484	26,064	18,201
Depreciation, depletion and amortization	174,569	127,961	48,649
Total operating expenses	294,395	232,077	108,182
Operating income	176,821	208,755	51,872
Other income (expense)
Interest expense, net of amounts capitalized	(35,811)	(26,462)	(6,392)
Derivatives	(68,131)	37,427	(17,819)
Other, net	(153)	2,266	58
Reorganization items, net	0	3,322	0
Income before income taxes	72,726	225,308	27,719
Income tax (expense) benefit	(2,137)	(523)	4,943
Net income	$ 70,589	$ 224,785	$ 32,662
Net income per share:
Basic (in dollars per share)	$ 4.67	$ 14.93	$ 2.18
Diluted (in dollars per share)	$ 4.67	$ 14.70	$ 2.17
Weighted average shares outstanding – basic	15,110	15,059	14,996
Weighted average shares outstanding – diluted	15,126	15,292	15,063
Oil and Gas, Exploration and Production [Member]
Revenues
Revenue from contract with customer	$ 434,713	$ 402,485	$ 140,886
Oil and Condensate [Member]
Revenues
Revenue from contract with customer	16,589	21,073	10,066
Natural Gas, Production [Member]
Revenues
Revenue from contract with customer	17,733	15,972	8,517
Product and Service, Other [Member]
Revenues
Revenue from contract with customer	$ 2,176	$ 1,479	$ 621

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income	$ 70,589	$ 224,785	$ 32,662
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax	(141)	82	(73)
Total other comprehensive income (loss), net of tax	(141)	82	(73)
Comprehensive income	$ 70,448	$ 224,867	$ 32,589

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 7,798	$ 17,864
Accounts receivable, net of allowance for doubtful accounts	70,716	66,038
Derivative assets	4,131	34,932
Income taxes receivable	1,236	2,471
Other current assets	4,458	5,125
Total current assets	88,339	126,430
Property and equipment, net (full cost method)	1,120,425	927,994
Derivative assets	2,750	10,100
Deferred income taxes	0	1,949
Other assets	6,724	2,481
Total assets	1,218,238	1,068,954
Current liabilities
Accounts payable and accrued liabilities	105,824	103,700
Derivative liabilities	23,450	991
Total current liabilities	129,274	104,691
Other liabilities	8,382	5,533
Deferred income taxes	1,424	0
Derivative liabilities	3,385	0
Long-term debt, net	555,028	511,375
Commitments and contingencies (Note 14)
Shareholders’ equity:
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued	0	0
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,135,598 and 15,080,594 shares issued as of December 31, 2019 and December 31, 2018, respectively	151	151
Paid-in capital	200,666	197,630
Retained earnings	319,987	249,492
Accumulated other comprehensive income (loss)	(59)	82
Total shareholders’ equity	520,745	447,355
Total liabilities and shareholders’ equity	$ 1,218,238	$ 1,068,954

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	45,000,000	45,000,000
Common stock, shares issued	15,135,598	15,080,594

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Cash Flows [Abstract]
Net increase (decrease) in cash and cash equivalents	$ (10,066)	$ 6,847	$ 4,256
Cash and cash equivalents - beginning of period	17,864	11,017	6,761
Cash and cash equivalents - end of period	7,798	17,864	11,017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	70,589	224,785	32,662
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash reorganization items	0	(3,322)	0
Depreciation, depletion and amortization	174,569	127,961	48,649
Derivative contracts:
Net (gains) losses	68,131	(37,427)	17,819
Cash settlements, net	(4,136)	(48,291)	(3,511)
Deferred income tax expense (benefit)	3,373	2,994	(4,943)
Loss (gain) on sales of assets, net	(5)	177	36
Non-cash interest expense	3,354	3,416	2,122
Share-based compensation (equity-classified)	4,082	4,618	3,809
Other, net	52	44	61
Changes in operating assets and liabilities:
Accounts receivable, net	(5,079)	(23,674)	(43,318)
Accounts payable and accrued expenses	4,690	21,109	28,542
Other assets and liabilities	574	(258)	(218)
Net Cash Provided by (Used in) Operating Activities	320,194	272,132	81,710
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net	(6,516)	(85,387)	(200,849)
Capital expenditures	(362,743)	(430,592)	(115,687)
Proceeds from sales of assets, net	215	7,683	869
Net cash used in investing activities	(369,044)	(508,296)	(315,667)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from credit facility borrowings	76,400	244,000	59,000
Repayment of credit facility borrowings	(35,000)	0	(7,000)
Proceeds from second lien note	0	0	196,000
Debt issuance costs paid	(2,616)	(989)	(9,787)
Proceeds received from rights offering, net	0	0	55
Other, net	0	0	(55)
Net cash provided by financing activities	38,784	243,011	238,213
Cash paid for:
Interest, net of amounts capitalized	32,398	22,599	4,102
Income taxes, net of (refunds)	(2,471)	0	0
Reorganization items, net	79	540	954
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Increase (Decrease) in Accounts Receivable, Acquisitions	(152)	(27,107)	(2,583)
Increase (Decrease) in Other Assets, Acquisitions	0	(743)	3,201
Increase (Decrease) in Accrued Liabilities, Acquisitions	(540)	(11,182)	(2,507)
Capital Expenditures, Period Increase (Decrease)	(3,602)	44	19,910
Increase (Decrease) in ARO, Acquisitions	$ 83	$ 385	$ 494

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Preferred Stock	Paid-in Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)
Balance as of beginning of period (in shares) at Dec. 31, 2016		14,992
Balance as of beginning of period at Dec. 31, 2016	$ 185,548	$ 150	$ 0	$ 190,621	$ (5,296)	$ 73
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	32,662				32,662
Share-based compensation				3,809
Restricted stock unit vesting (in shares)		27
Restricted stock unit vesting	(351)			(351)
Other	29			(44)	0	73
Balance as of end of period (in shares) at Dec. 31, 2017		15,019
Balance as of end of period at Dec. 31, 2017	221,639	$ 150	0	194,123	27,366	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	224,785				224,785
Share-based compensation				4,618
Restricted stock unit vesting (in shares)		61
Restricted stock unit vesting	(1,110)	$ 1		(1,111)
Other	(82)					(82)
Balance as of end of period (in shares) at Dec. 31, 2018		15,080
Balance as of end of period at Dec. 31, 2018	447,355	$ 151	0	197,630	249,492	82
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	70,589				70,589
Share-based compensation				4,082
Restricted stock unit vesting (in shares)		56
Restricted stock unit vesting	(1,046)			(1,046)
Other	141					141
Balance as of end of period (in shares) at Dec. 31, 2019		15,136
Balance as of end of period at Dec. 31, 2019	$ 520,745	$ 151	$ 0	$ 200,666	$ 319,987	$ (59)

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Nature of Operations	Nature of Operations Penn Virginia Corporation (together with its consolidated subsidiaries unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Basis of Presentation [Abstract]
Basis of Presentation	2. Basis of Presentation Adoption of Recently Issued Accounting Pronouncements and Comparability to Prior Periods Effective January 1, 2019, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) 2016–02, Leases (“ASU 2016–02”) and related amendments to accounting principles generally accepted in the United States of America (“GAAP”) which, together with ASU 2016–02, represent Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC Topic 842”). We adopted ASC Topic 842 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2019 (see Note 11 for the impact and disclosures associated with the adoption of ASC Topic 842). Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent ASC Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606). Comparative periods and related disclosures have not been restated for the application of ASC Topic 842 and ASC Topic 606. Accordingly, certain components of our Consolidated Financial Statements are not comparable between periods and the Consolidated Statement of Operations for the year ended December 31, 2017 is presented based on prior GAAP for both revenue recognition and leases in their entirety. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. We will adopt ASU 2016–13 effective January 1, 2020. While we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures, we will be applying new procedures and controls to our customer and partner billing processes in order to apply the expected loss model on a monthly basis. Going Concern Presumption Our Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Subsequent Events Management has evaluated all of our activities through the issuance date of our Consolidated Financial Statements and has concluded that, other than the entry into additional commodity derivative contracts including crude oil and natural gas hedges and certain interest rate swap agreements (see Note 6), all in the ordinary course of business, no subsequent events have occurred that would require recognition in our Consolidated Financial Statements or disclosure in the Notes thereto.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation Our Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated. Use of Estimates Preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these Notes. Actual results could differ from those estimates. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Derivative Instruments From time to time, we utilize derivative instruments to mitigate our financial exposure to commodity price and interest rate volatility. The derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, generally take the form of collars and swaps. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors. All derivative instruments are recognized in our Consolidated Financial Statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. Our derivative instruments are not formally designated as hedges. We recognize changes in fair value in earnings currently as a component of the Derivatives caption in our Consolidated Statements of Operations. We have experienced and could continue to experience significant changes in the amount of derivative gains or losses recognized due to fluctuations in the value of the underlying derivative contracts, which fluctuate with changes in commodity prices and interest rates. Oil and Gas Properties We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”). Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (a “Ceiling Test”). The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. Depreciation, Depletion and Amortization DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. Other Property and Equipment Other property and equipment consists primarily of gathering systems and related support equipment. Property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property and equipment using the straight-line balance method over the estimated useful life of each asset as follows: Gathering systems – fifteen to twenty years and Other property and equipment – three to twenty years. Leases We determine if an arrangement is a lease at the inception of the underlying contractual arrangement. In addition, we determine whether the lease is classified as operating or financing. As of the date of adoption of ASC Topic 842 and through December 31, 2019, we do not have any financing leases. Leases are included in the captions “Other assets,” “Accounts payable and accrued liabilities” and “Other liabilities” on our Consolidated Balance Sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Notes 11 and 12. ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to 5 years , our secured incremental borrowing rate is primarily based on the rates applicable to our credit agreement (the “Credit Facility”). We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We have elected to apply a practical expedient provided in ASC Topic 842 to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term. Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we have elected to not include the underlying ROU assets and lease obligations on our Consolidated Balance Sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11. Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11. Asset Retirement Obligations We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our Consolidated Statements of Operations. Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize tax credits and operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent they arise, as a component of interest expense and penalties as a component of income tax expense. We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain. Revenue Recognition and Associated Costs Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through December 31, 2019, we were the agent and our midstream processing vendors were our customers with respect to all of our NGL product sales. Natural gas . Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services . We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Share-Based Compensation Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period except for those that are based on performance which are amortized on a graded basis over the term of the applicable performance periods. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Consolidated Statements of Operations. Reorganization Items

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2019
Acquisitions and Divestitures [Abstract]
Acquisitions and Divestitures	. Acquisitions and Divestitures Acquisitions Eagle Ford Working Interests In 2019, we acquired working interests in certain properties for which we are the operator from our joint venture partners in a series of transactions for cash consideration of $ 6.5 million . Funding for these acquisition was provided by borrowings under the Credit Facility. Hunt Acquisition In December 2017, we entered into a purchase and sale agreement with Hunt Oil Company (“Hunt”) to acquire certain oil and gas assets in the Eagle Ford Shale, covering approximately 9,700 net acres primarily in Gonzales County, Texas for $ 86.0 million in cash (the “Hunt Acquisition”). The Hunt Acquisition had an effective date of October 1, 2017 and closed in 2018. We paid total cash consideration of $ 83.0 million , net of suspended revenues received, for the Hunt Acquisition in 2018. We also acquired working interests in certain wells that we previously drilled as operator in which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $ 13.8 million , along with $ 0.2 million of certain working capital adjustments which we have reflected as components of the total net assets acquired. We funded the Hunt Acquisition with borrowings under the Credit Facility. We incurred a total of $ 0.5 million of transaction costs for legal, due diligence and other professional fees associated with the Hunt Acquisition, including $ 0.1 million in 2017 and $ 0.4 million in 2018. These costs have been recognized as a component of our G&A expenses. We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt: Assets Oil and gas properties - proved $ 82,443 Oil and gas properties - unproved 16,339 Liabilities Revenue suspense 1,448 Asset retirement obligations 356 Net assets acquired $ 96,978 Cash consideration paid to Hunt, net $ 82,955 Application of working capital adjustments 245 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 96,978 Devon Acquisition In July 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”), with Devon Energy Corporation (“Devon”) to acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205 million in cash (the “Devon Acquisition”). We also acquired working interests in the Devon Properties from parties that had tag-along rights to sell their interests under the Purchase Agreement. The Devon Acquisition had an effective date of March 1, 2017 and closed in September 2017. We paid total cash consideration of $ 199.8 million for the Devon Acquisition including $ 200.9 million paid in 2017 net of $1.1 million of suspended revenues and other adjustments paid to us in 2018 in connection with a final settlement. The Devon Acquisition was financed with the net proceeds received from borrowings under the $200 million Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 9 for terms of the Second Lien Facility) and incremental borrowings under the Credit Facility. We incurred a total of $1.3 million of transaction costs associated with the Devon Acquisitions during 2017, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our G&A expenses. We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred: Assets Oil and gas properties - proved $ 42,866 Oil and gas properties - unproved 146,686 Other property and equipment 8,642 Liabilities Revenue suspense 355 Asset retirement obligations 494 Net assets acquired $ 197,345 Cash consideration paid to Devon and tag-along parties, net $ 199,796 Application of working capital adjustments, net (2,451 ) Total consideration $ 197,345 Valuation of Acquisitions The fair values of the oil and gas properties acquired in the Hunt and Devon Acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future cash flows (v) the timing of or development plans and (vi) a market-based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to replacement costs for similar assets adjusted for the age and normal use of the underlying assets. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP. Impact of Acquisitions on Actual and Pro Forma Results of Operations The results of operations attributable to the Hunt and Devon Acquisitions have been included in our Consolidated Financial Statements for the periods after March 1, 2018 and September 30, 2017, respectively. The Devon Acquisition provided revenues and estimated earnings, excluding allocations of interest expense and income taxes, of approximately $9 million and $4 million , respectively, for the period from October 1, 2017 through December 31, 2017. The Hunt Acquisition provided revenues and estimated earnings, excluding allocations of interest expense and income taxes, of approximately $ 0.4 million and $ 0.2 million , respectively, for the period from March 1, 2018 through March 31, 2018. As the properties and working interests acquired in connection with the Hunt and Devon Acquisitions are included within our existing Eagle Ford acreage, it is not practical or meaningful to disclose revenues and earnings unique to those assets for periods beyond those during which they were acquired, as they were fully integrated into our regional operations soon after their acquisition. The following table presents unaudited summary pro forma financial information for the years ended December, 31, 2018 and 2017 assuming the Hunt and Devon Acquisitions and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. Year Ended December 31, 2018 2017 Total revenues $ 446,077 $ 209,015 Net income $ 227,930 $ 30,861 Net income per share - basic $ 15.14 $ 2.06 Net income per share - diluted $ 14.91 $ 2.05 Divestitures Mid-Continent Divestiture In June 2018, we entered into a purchase and sale agreement with a third party to fully divest our Mid-Continent operations and sell all of our remaining oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $ 6.0 million in cash, subject to customary adjustments. The sale had an effective date of March 1, 2018 and closed on July 31, 2018, and we received proceeds of $ 6.2 million . The sale proceeds and de-recognition of certain assets and liabilities were recorded as a reduction of our net oil and gas properties. In November 2018, we paid $ 0.5 million , including $ 0.2 million of suspended revenues, to the buyer in connection with the final settlement. The Mid-Continent properties had AROs of $ 0.3 million as well as a net working capital deficit attributable to the oil and gas properties of $ 1.3 million as of July 31, 2018. The net pre-tax operating income attributable to the Mid-Continent assets was $ 1.6 million and $ 2.2 million for the years ended December 31, 2018 and December 31, 2017, respectively. Sales of Undeveloped Acreage, Rights and Other Assets In February 2018, we sold all of our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire in 2019. In March 2018, we sold certain undeveloped deep leasehold rights in our former Mid-Continent operating region in Oklahoma, and in May 2018, we sold certain pipeline assets in our former Marcellus Shale operating region. We received a combined total of $ 1.7 million for these leasehold and other assets which were applied as a reduction of our net oil and gas properties.

Accounts Receivable and Major C

Accounts Receivable and Major Customers	12 Months Ended
	Dec. 31, 2019
Receivables [Abstract]
Accounts Receivable and Major Customers	Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2019 2018 Customers $ 63,165 $ 59,030 Joint interest partners 6,929 6,404 Other 674 640 70,768 66,074 Less: Allowance for doubtful accounts (52 ) (36 ) $ 70,716 $ 66,038 For the year ended December 31, 2019 , four customers accounted for $354.6 million , or approximately 76% of our consolidated product revenues. The revenues generated from these customers during 2019 were $172.3 million , $84.6 million , $50.7 million and $47.0 million or 37% , 18% , 11% and 10% of the consolidated total, respectively. As of December 31, 2019 , $44.5 million , or approximately 70% of our consolidated accounts receivable from customers was related to these customers. For the year ended December 31, 2018 , three customers accounted for $304.3 million , or approximately 69% of our consolidated product revenues. The revenues generated from these customers during 2018 were $173.0 million , $71.5 million and $59.8 million , or approximately 39% , 16% and 14% of the consolidated total, respectively. As of December 31, 2018 , $28.6 million , or approximately 48% of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. The allowance for doubtful accounts is entirely attributable to certain receivables from joint interest partners. Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contracts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $ 2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We utilize derivative instruments, typically swaps, two- and three-way collars and enhanced swaps which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges in the context of GAAP. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit future product revenues and interest expense from favorable price and rate movements. In addition, we do not utilize derivative instruments for speculative purposes. As of December 31, 2019, we were unhedged with respect to NGL and natural gas production and we had no interest rate hedges outstanding. The following is a general description of the derivative instruments we have employed: Swaps . The counterparty to a swap contract is required to make a payment to us if the settlement price for any settlement period is below the swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap price for such contract. Two-Way Collars . The counterparty to a two-way collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such collar contract. Three-Way Collars . A three-way collar consists of (i) a purchased put option which establishes a floor price for the collar, (ii) a sold call option which establishes a ceiling price of the collar and (iii) a sold put option which establishes a sub-floor price. Three-way collars are settled based on differences between the floor or ceiling prices and the settlement price of a referenced index or the difference between the floor price and sub-floor price. If the settlement price of the referenced index is below the sub-floor price, the counterparty is required to make a payment to us for the difference between the floor price and sub-floor price. If the settlement price of the referenced index is between the floor price and sub-floor price, the counterparty is required to make a payment to us for the difference between the floor price and the settlement price of the referenced index. If the settlement price of the referenced index is between the floor price and ceiling price, no payments are due to or from either party. If the settlement price of the referenced index is above the ceiling price, we are required to make a payment to the counterparty for the difference. Enhanced Swaps . An enhanced swap consists of a sold put option with the associated premiums rolled into an enhanced fixed price swap. The counterparty to an enhanced swap contract is required to make a payment to us if the settlement price for any settlement period is below the swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap price for such contract. Additionally, we are required to make a payment to the counterparty if the settlement price for any settlement period is below the sold-put strike price. Effectively, when the settlement price for any settlement period is below the sold-put strike price, we receive the swap price minus the sold put strike price. We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate (“ WTI ”), Louisiana Light Sweet (“ LLS ”) and Magellan East Houston (“ MEH ”) crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. Subsequent Events In January of 2020, we entered into additional commodity hedge contracts as well as certain interest rate swap transactions. We replaced a portion of two crude oil swaps with a costless collar for 2,000 BOPD for April through December 2020 with floor and ceiling prices of $ 48.00 and $ 57.10 per barrel. We entered into a costless collar for Henry Hub natural gas for 270,000 MMBTU per month with a term from February through December of 2020 with floor and ceiling prices of $ 2.00 and $ 2.18 per MMBTU, respectively. In January and February 2020, we entered into interest rate swaps contracts through May 2022 for a notional amount of $ 300 million , paying a weighted-average fixed rate of 1.36 %. The following table sets forth our commodity derivative contracts as of December 31, 2019 : 1Q2020 2Q2020 3Q2020 4Q2020 1Q2021 2Q2021 3Q2021 4Q2021 NYMEX WTI Crude Swaps Average Volume Per Day (barrels) 15,648 12,648 10,630 10,630 3,333 3,297 1,630 1,630 Weighted Average Swap Price ($/barrel) $ 55.34 $ 54.96 $ 54.77 $ 54.77 $ 55.89 $ 55.89 $ 55.50 $ 55.50 NYMEX WTI Purchased Puts/Sold Calls Average Volume Per Day (barrels) 3,297 4,891 1,667 1,648 Weighted Average Purchased Put Price ($/barrel) $ 55.00 $ 55.00 $ 55.00 $ 55.00 Weighted Average Sold Call ($/barrel) $ 57.69 $ 58.42 $ 58.00 $ 58.00 NYMEX WTI Sold Puts Average Volume Per Day (barrels) 5,000 4,945 1,630 1,630 Weighted Average Sold Put Price ($/barrel) $ 44.00 $ 44.00 $ 44.00 $ 44.00 MEH Crude Swaps Average Volume Per Day (barrels) 2,000 2,000 2,000 2,000 Weighted Average Swap Price ($/barrel) $ 61.03 $ 61.03 $ 61.03 $ 61.03 Financial Statement Impact of Derivatives The impact of our derivatives activities on income is included in the “Derivatives” caption on our Consolidated Statements of Operations. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Consolidated Statements of Cash Flows under the “Net (gains) losses” and “Cash settlements, net.” The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2019 2018 2017 Derivative gains (losses) recognized in the Consolidated Statements of Operations $ (68,131 ) $ 37,427 $ (17,819 ) Cash settlements recognized in the Consolidated Statements of Cash Flows $ (4,136 ) $ (48,291 ) $ (3,511 ) The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our Consolidated Balance Sheets as of the dates presented: Fair Values December 31, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 4,131 $ 23,450 $ 34,932 $ 991 Commodity contracts Derivative assets/liabilities – noncurrent 2,750 3,385 10,100 — $ 6,881 $ 26,835 $ 45,032 $ 991 As of December 31, 2019 , we reported net commodity derivative liabilities of $20.0 million . The contracts associated with this position are with nine counterparties, all of which are investment grade financial institutions and are participants in the Credit Facility. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment The following table summarizes our property and equipment as of the dates presented: December 31, 2019 2018 Oil and gas properties: Proved $ 1,409,219 $ 1,037,993 Unproved 53,200 63,484 Total oil and gas properties 1,462,419 1,101,477 Other property and equipment 25,915 20,383 Total property and equipment 1,488,334 1,121,860 Accumulated depreciation, depletion and amortization (367,909 ) (193,866 ) $ 1,120,425 $ 927,994 Unproved property costs of $ 53.2 million and $ 63.5 million have been excluded from amortization as of December 31, 2019 and December 31, 2018 , respectively. An additional $0.3 million of costs, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of December 31, 2018. The total costs not subject to amortization as of December 31, 2019 were incurred in the following periods: $ 1.3 million in 2019, $ 6.1 million in 2018, $ 43.1 million in 2017 and the remaining $ 2.7 million in 2016. We transferred $ 16.8 million and $82.8 million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool during the years ended December 31, 2019 and 2018 , respectively. We capitalized internal costs of $ 4.1 million , $3.7 million and $2.4 million and interest of $ 4.1 million , $9.1 million and $2.7 million during the year ended December 31, 2019 , 2018 and 2017 respectively, in accordance with our accounting policies. Average DD&A per barrel of oil equivalent of proved oil and gas properties was $ 17.25 , $16.11 and $12.87 for the years ended December 31, 2019 , 2018 and 2017

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table reconciles our AROs as of the dates presented, which are included in the “Other liabilities” caption on our Consolidated Balance Sheets: Year Ended December 31, 2019 2018 Balance at beginning of period $ 4,314 $ 3,286 Changes in estimates (2 ) 354 Liabilities incurred 290 335 Liabilities settled (67 ) (8 ) Acquisitions of properties 83 385 Sale of properties — (310 ) Accretion expense 316 272 Balance at end of period $ 4,934 $ 4,314

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following table summarizes our long-term debt as of the dates presented: December 31, 2019 December 31, 2018 Principal Unamortized Discount and Issuance Costs 1 Principal Unamortized Discount and Issuance Costs 1 Credit facility 2 $ 362,400 $ 321,000 Second lien term loan 200,000 $ 7,372 200,000 $ 9,625 Totals 562,400 7,372 521,000 9,625 Less: Unamortized discount (2,415 ) (3,159 ) Less: Unamortized deferred issuance costs (4,957 ) (6,466 ) Long-term debt, net $ 555,028 $ 511,375 _____________________________________________ 1 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method. 2 Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its contractual term, have been presented as a component of Other assets (see Note 12) and are being amortized over the term of the Credit Facility using the straight-line method. Credit Facility The Credit Facility provides for a $1.0 billion revolving commitment and $500 million borrowing base including a $25 million sublimit for the issuance of letters of credit. In December 2019, we completed our fall borrowing base redetermination and our lenders affirmed the $500 million borrowing base. In the years ended December 31, 2019 and December 31, 2018 , we paid and capitalized issue costs of $2.6 million and $0.9 million , respectively in connection with amendments to the Credit Facility. Availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital. We had $0.4 million in letters of credit outstanding as of December 31, 2019 and December 31, 2018 . In May 2019, maturity of the Credit Facility was extended to May 2024 from September 2020; provided that on June 30, 2022, unless we have either extended the maturity date of the Second Lien Facility described below to a date that is at least 91 days after the May 7, 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will mean June 30, 2022. The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 0.50% to 1.50% , determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 1.50% to 2.50% , determined based on the average availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on LIBOR borrowings is payable every one, three or six months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of December 31, 2019 , the actual interest rate on the outstanding borrowings under the Credit Facility was 3.75% . Unused commitment fees are charged at a rate of 0.375% to 0.50% , depending upon utilization. The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on our ability or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets. The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 4.00 to 1.00. The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), limitations on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. The Credit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of December 31, 2019 , and through the date upon which the Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Credit Facility. Second Lien Facility On September 29, 2017, we entered into the Second Lien Facility. We received net proceeds of $ 187.8 million from the Second Lien Facility net of an original issue discount (“OID”) of $ 4.0 million and issue costs of $ 8.2 million . The proceeds from the Second Lien Facility were used to fund the Devon Acquisition and related fees and expenses. The maturity date under the Second Lien Facility is September 29, 2022. The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00% . As of December 31, 2019 , the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.81% . Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.89% . Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six-month interest period), at our election and is computed on the basis of a 360-day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): from October 2019 through September 2020, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: from October 2019 through September 2020, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the Subsidiary Guarantors. The Second Lien Facility has no financial covenants, but contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), limitations on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends and transactions with affiliates and other customary covenants. As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term loan. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility. As of December 31, 2019 , and through the date upon which the Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Second Lien Facility.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The following table summarizes our provision for income taxes for the periods presented: Year Ended December 31, 2019 2018 2017 Current income taxes (benefit) Federal $ (1,236 ) $ (2,471 ) $ — (1,236 ) (2,471 ) — Deferred income taxes (benefit) Federal 1,236 2,471 (4,943 ) State 2,137 523 — 3,373 2,994 (4,943 ) $ 2,137 $ 523 $ (4,943 ) The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our income (loss) before income taxes and our reported income tax benefit for the periods presented: Year Ended December 31, 2019 2018 2017 Computed at federal statutory rate $ 15,272 21.0 % $ 47,315 21.0 % $ 9,701 35.0 % State income taxes, net of federal income tax benefit 1,494 2.1 % 1,743 0.8 % (1,383 ) (5.0 )% Change in valuation allowance (14,240 ) (19.6 )% (48,820 ) (21.7 )% (24,353 ) (87.8 )% Effect of rate change on the valuation allowance — — % — — % (86,612 ) (312.5 )% Effect of rate change — — % — — % 86,612 312.5 % Reorganization adjustments — — % — — % 10,760 38.8 % Other, net (389 ) (0.5 )% 285 0.1 % 332 1.2 % $ 2,137 3.0 % $ 523 0.2 % $ (4,943 ) (17.8 )% The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented: December 31, 2019 2018 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 175,221 $ 163,437 Alternative minimum tax (“AMT”) credit carryforwards 1,236 2,471 Asset retirement obligations 1,073 647 Pension and postretirement benefits 340 441 Share-based compensation 880 546 Fair value of derivative instruments 4,191 — Interest expense limitation 11,463 3,128 Other 2,441 2,590 196,845 173,260 Less: Valuation allowance (114,939 ) (128,650 ) Total net deferred tax assets 81,906 44,610 Deferred tax liabilities: Property and equipment 83,330 33,413 Fair value of derivative instruments — 9,248 Total deferred tax liabilities 83,330 42,661 Net deferred tax assets (liabilities) $ (1,424 ) $ 1,949 Continuing Impact of 2017 Tax Reform In 2017, the U.S. Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA provided for broad and complex changes to the U.S. tax code (the “Code”). In addition to the reduction in the U.S. federal corporate income tax rate from 35% to 21% , the most significant aspects of the TCJA that continue to have a material impact on us are those attributable to: (i) the repeal of the corporate AMT, (ii) limitations on deductible interest expense and (iii) the utilization and limitations on NOLs. The specific impact of these TCJA-related items are described in further detail below in our discussion of the income tax provision and our deferred tax assets and liabilities. As a result of the repeal of the AMT, our existing AMT credit carryovers became refundable beginning with the 2018 tax year. The AMT credit carryforwards are used to offset current year regular tax liabilities with 50 percent of any excess remaining credit per year being refundable as part of the annual income tax filing. Income Tax Provision The provision for the years ended December 31, 2019 and 2018 includes current federal benefits of $ 1.2 million and $ 2.5 million attributable to the anticipated refund of AMT credits for the 2019 and 2018 tax years, respectively. The amount for 2019 has been recognized on our Consolidated Balance Sheet as of December 31, 2019 as a current asset. The $ 2.5 million attributable to 2018 was refunded to us in 2019. These benefits have been offset by corresponding decreases in the deferred tax asset associated with AMT credit carryforwards giving rise to deferred federal expenses for the years ended December 31, 2019 and 2018, respectively. In addition, we have a recognized deferred state tax expenses of $ 2.1 million and $ 0.5 million attributable to property and equipment for overall effective tax rates of 3.0% and 0.2% for the years ended December 31, 2019 and 2018, respectively. The remaining AMT credit carryforwards of approximately $ 1.2 million will be reclassified from deferred tax assets, where they are classified as of December 31, 2019, to income taxes receivable upon the filing of federal returns in future years. In connection with the TCJA, we recorded an income tax charge of $ 86.6 million for the year ended December 31, 2017, which consisted of a reduction of deferred tax assets previously valued at 35% . We recorded a corresponding decrease in our deferred tax asset valuation allowance representing an income tax benefit for the same amount. In addition, our provision for the year ended December 31, 2017 included federal income taxes of $9.7 million applied at the statutory rate of 35 % and an adjustment of $10.8 million attributable to reductions in certain tax attributes of property and other adjustments of $0.3 million applied in connection with the filing of our 2016 income tax returns. These expenses were effectively offset by benefits attributable to the reduction in our deferred tax asset valuation allowance of $24.4 million and state income tax benefits of $1.4 million resulting in a net tax deferred benefit of $4.9 million . Deferred Tax Assets and Liabilities As of December 31, 2019 , we had federal NOL carryforwards of approximately $613.4 million , a substantial portion of which, if not utilized, expire between 2032 and 2037. NOLs incurred after January 1, 2018 can be carried forward indefinitely. State NOL carryforwards of approximately $437.9 million expire between 2024 and 2037. Because of the change in ownership provisions of the Code, use of a portion of our federal and state NOLs may be limited in future periods. As of December 31, 2019, we carried a valuation allowance against our federal and state deferred tax assets of $114.9 million . We considered both the positive and negative evidence in determining whether it was more likely than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax assets considered realizable could, however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence is no longer present and additional weight is given to subjective positive evidence, including projections for growth. The net deferred tax liability recognized on the Consolidated Balance Sheet as of December 31, 2019 is attributable to certain state deferred tax liabilities associated with property and equipment in excess of federal deferred tax assets associated with refundable AMT credit carryforwards for tax years ending after 2019. The net deferred tax asset recognized on the Consolidated Balance Sheet as of December 31, 2018 is attributable to federal deferred tax assets associated with AMT credit carryforwards in excess of certain state deferred tax liabilities attributable to property and equipment. The valuation allowance related to all other net deferred tax assets remains in full as of December 31, 2019 and 2018. Other Income Tax Matters We had no liability for unrecognized tax benefits as of December 31, 2019 and 2018 . There were no interest and penalty charges recognized during the years ended December 31, 2019 , 2018 and 2017 . Tax years from 2015 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Leases Adoption of ASC Topic 842 Effective January 1, 2019, we adopted ASC Topic 842 and have applied the guidance therein to all of our contracts and agreements explicitly identified as leases as well as other contractual arrangements that we have determined to include or otherwise have the characteristics of a lease as defined in ASC Topic 842. As illustrated in the disclosures below, the adoption of ASC Topic 842 resulted in the recognition of certain assets and liabilities on our Consolidated Balance Sheet and changes in the amounts and timing of lease cost recognition in our Consolidated Statements of Operations as compared to prior GAAP. We have adopted ASC Topic 842 using the optional transition approach with an adjustment to the beginning balance of retained earnings as of January 1, 2019. Accordingly, our 2019 financial statements are not comparable with respect to leases in effect during all periods prior to January 1, 2019. On January 1, 2019, we recognized operating lease right-of-use (“ROU”) assets of $ 2.5 million and operating lease obligations of $ 2.8 million on our Consolidated Balance Sheet for operating leases in effect on that date. We recorded an immaterial adjustment to the beginning balance of retained earnings as of January 1, 2019 representing the difference between the operating lease ROU assets and operating lease obligations recognized upon adoption net of amounts already included in our liabilities as of December 31, 2018 that were attributable to straight-line lease expense in excess of amounts paid for certain operating leases. We did not identify any finance leases, as defined in ASC Topic 842, upon the date of initial adoption. Lease Arrangements and Supplemental Disclosures We have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs and our field compressors. Our primary variable lease includes our field gas gathering and gas lift agreement with a midstream service provider and the lease payments are charged on a volumetric basis at a contractual fixed rate. The following table summarizes the components of our total lease cost, as determined in accordance with ASC Topic 842, for the twelve months ended December 31, 2019 : Operating lease cost $ 773 Short-term lease cost 36,202 Variable lease cost 23,762 Less: Amounts charged as drilling costs 1 (33,354 ) Total lease cost recognized in the Condensed Consolidated Statement of Operations 2 $ 27,383 ___________________ 1 Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs. 2 Includes $ 12.1 million recognized in Gathering, processing and transportation, $ 14.5 million recognized in Lease operating and $ 0.8 million recognized in G&A for the twelve months ended December 31, 2019 . Operating lease rental expense, as determined in accordance with prior GAAP was $2.7 million and $1.0 million, for the years ended December 31, 2018 and 2017 , related primarily to field equipment, office equipment and office leases. The substantial difference between operating lease rental expense disclosed in accordance with prior GAAP and that provided in the table above for 2019 in accordance with ASC Topic 842 is attributable to the aforementioned field gas gathering and gas lift agreement which has been determined to be a variable lease under ASC Topic 842. The following table summarizes supplemental cash flow information, as determined in accordance with ASC Topic 842, related to leases for the twelve months ended December 31, 2019 : Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 659 ROU assets obtained in exchange for lease obligations: Operating leases 1 $ 3,325 ___________________ 1 Includes $ 2.5 million recognized upon adoption of ASC Topic 842 and $ 0.8 million obtained during the twelve months ended December 31, 2019 . The following table summarizes supplemental balance sheet information related to leases as of December 31, 2019 : ROU assets - operating leases $ 2,740 Current operating lease obligations $ 847 Noncurrent operating lease obligations 2,232 Total operating lease obligations $ 3,079 Weighted-average remaining lease term Operating leases 4.1 Years Weighted-average discount rate Operating leases 5.97 % Maturities of operating lease obligations for the years ending December 31, 2020 $ 847 2021 830 2022 834 2023 833 2024 139 Total undiscounted lease payments 3,483 Less: imputed interest (404 ) Total operating lease obligations $ 3,079

Additional Balance Sheet Detail

Additional Balance Sheet Detail	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Detail	Additional Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2019 2018 Other current assets: Tubular inventory and well materials $ 2,989 $ 4,061 Prepaid expenses 1,469 1,064 $ 4,458 $ 5,125 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 3,952 $ 2,437 Right-of-use assets - operating leases 2,740 — Other 32 44 $ 6,724 $ 2,481 Accounts payable and accrued liabilities: Trade accounts payable $ 30,098 $ 16,507 Drilling costs 18,832 22,434 Royalties 44,537 51,212 Production, ad valorem and other taxes 3,244 2,418 Compensation and benefits 5,272 4,489 Interest 730 670 Current operating lease obligations 847 — Other 2,264 5,970 $ 105,824 $ 103,700 Other liabilities: Asset retirement obligations $ 4,934 $ 4,314 Noncurrent operating lease obligations 2,232 — Defined benefit pension obligations 873 857 Postretirement health care benefit obligations 343 362 $ 8,382 $ 5,533

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	13. Fair Value Measurements We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below. Fair value measurements are classified and disclosed in one of the following three categories: • Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value. • Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. Due to the short-term nature of their maturities, the carrying value of our cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Our derivatives are marked-to-market and presented at their values. The carrying value of our long-term debt, which includes the Credit Facility and the Second Lien Facility, approximated their fair values as they represent variable-rate debt and their interest rates are reflective of market rates. Recurring Fair Value Measurements Certain financial assets and liabilities are measured at fair value on a recurring basis on our Consolidated Balance Sheets. The following tables summarize the valuation of those assets and (liabilities) as of the dates presented: As of December 31, 2019 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 4,131 $ — $ 4,131 $ — Commodity derivative assets – noncurrent 2,750 — 2,750 — Liabilities: Commodity derivative liabilities – current $ (23,450 ) $ — $ (23,450 ) $ — Commodity derivative liabilities – noncurrent (3,385 ) — (3,385 ) — As of December 31, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 34,932 $ — $ 34,932 $ — Commodity derivative assets – noncurrent 10,100 — 10,100 — Liabilities: Commodity derivative liabilities – current $ (991 ) $ — $ (991 ) $ — Commodity derivative liabilities – noncurrent — — — — Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during any period in the years ended December 31, 2019 , 2018 and 2017 . We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for WTI , LLS and MEH crude oil closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input. Non-Recurring Fair Value Measurements In addition to the fair value measurements applied with respect to the Hunt and Devon Acquisitions, as described in Note 4, the most significant non-recurring fair value measurements utilized in the preparation of our Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The following table sets forth our significant commitments as of December 31, 2019 , by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Other Commitments 2020 $ 12,962 $ 289 2021 12,962 140 2022 12,962 70 2023 12,962 — 2024 12,962 — Thereafter 37,789 — Total $ 102,599 $ 499 Drilling and Completion Commitments As of December 31, 2019 , we had contractual commitments on a pad-to-pad basis for two drilling rigs. Additionally, we have a one-year agreement, effective January 1, 2020, which can be terminated with 30 days ' notice by either party, to utilize certain frac services and related materials, with no minimum commitment. Gathering and Intermediate Transportation Commitments We have long-term agreements with Nuevo Dos Gathering and Transportation, LLC (“Nuevo G&T”) and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”), successor to Republic Midstream, LLC and affiliates, to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in South Texas as well as volume capacity support for certain downstream interstate pipeline transportation. Nuevo is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment of 8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. Under a marketing agreement, we have a commitment to sell 8,000 barrels per day of crude oil (gross) to Nuevo, or to any third party, utilizing Nuevo Marketing's capacity in a downstream interstate pipeline through 2026. Other Commitments We have entered into certain contractual arrangements for other products and services. We have purchase commitments for certain materials as well as minimum commitments under information technology licensing and service agreements, among others. Legal We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of December 31, 2019, we had a reserve in the amount of $ 0.3 million included in Accounts payable and accrued liabilities for the estimated settlement of disputes with a joint venture partner regarding certain transactions that occurred in prior years. Environmental Compliance Extensive federal, state and local laws govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2019 , we have recorded AROs of $4.9 million

Shareholders' Equity

Shareholders' Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Shareholders' Equity	Shareholders’ Equity Preferred Stock As of December 31, 2019 and December 31, 2018 , there were 5,000,000 shares of preferred stock authorized with none issued or outstanding. Common Stock As of December 31, 2019 and December 31, 2018 , there were 15,135,598 and 15,080,594 shares of Common Stock outstanding, respectively, with a par value of $ 0.01 per share. We have a total of 45,000,000 shares authorized. We have not paid any cash dividends on our common stock. In addition, our Credit Facility and Second Lien Facility have restrictive covenants that limit our ability to pay dividends. Paid-in Capital Represents the value of consideration we received in excess of par value for the original issuance of our common stock net of costs directly attributable to the issuance transactions. In addition, paid-in capital includes amounts attributable to the amortized cost of share-based awards that have been granted to our employees and directors, net of any adjustments with the ultimate vesting of such awards. Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income and losses are entirely attributable to our pension and postretirement health care benefit obligations. The accumulated other comprehensive income, net of tax, was less than $0.1 million

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-based Compensation and Other Benefit Plans	Share-Based Compensation and Other Benefit Plans We reserved 1,424,600 shares of Common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 360,615 time-vested restricted stock units (“RSUs”) and 113,592 performance restricted stock units (“PRSUs”) have been granted as of December 31, 2019 . We recognized $4.1 million, $4.6 million and $3.8 million of share-based compensation expense for the years ended December 31, 2019 , 2018 and 2017 , respectively. All of our share-based compensation awards are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards has been measured at the grant date and recognized over the applicable vesting periods as a non-cash item of expense. Time-Vested Restricted Stock Units A restricted stock unit entitles the grantee to receive a share of common stock upon the vesting of the restricted stock unit. The grant date fair value of our time-vested restricted stock unit awards are recognized on a straight-line basis over the applicable vesting period. The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs: Restricted Stock Units Weighted-Average Grant Date Fair Value Balance at beginning of year 208,040 $ 47.35 Granted 13,175 $ 30.35 Vested (74,888 ) $ 39.40 Forfeited (9,451 ) $ 51.71 Balance at end of year 136,876 $ 49.76 As of December 31, 2019 , we had $5.0 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.1 years . The total grant-date fair values of RSUs that vested in 2019 , 2018 and 2017 was $3.0 million , $3.3 million and $0.8 million , respectively. Performance Restricted Stock Units In the years ended December 31, 2019 and December 31, 2017, we granted 15,066 and 98,526 PRSUs, respectively to members of our management. There were no PRSUs granted for the year ended December 31, 2018. The PRSUs were issued collectively in one to three separate tranches with individual three-year performance periods beginning in January 2017, 2018, 2019 and 2020, respectively. Vesting of the PRSUs can range from zero to 200% of the original grant based on the performance of our common stock relative to an industry index or for those granted in 2019, a peer group of companies. Due to their market condition, the PRSUs are being charged to expense using graded vesting over a maximum of five years . The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation with a range of $47.70 to $65.28 per PRSU for the 2017 grants and $34.02 for the 2019 grant. The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2019 and 2017 are presented as follows: 2019 2017 Expected volatility 49.9 % 59.63% to 62.18% Dividend yield 0.0% 0.0% Risk-free interest rate 1.66 % 1.44% to 1.51% The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Units Weighted-Average Grant Date Fair Value Balance at beginning of year 89,071 $ 58.69 Granted 15,066 $ 34.02 Vested (3,917 ) $ 63.25 Forfeited (1,083 ) $ 63.25 Expired (19,223 ) $ 62.92 Balance at end of year 79,914 $ 52.73 Executive Transition and Retirement Effective December 2, 2019, Mr. Steven A. Hartman separated from the Company. In accordance with his separation and transition agreement (“Hartman Separation Agreement”), we recorded a charge of $ 0.5 million for severance and other cash benefits that were paid in the first quarter of 2020. The Hartman Separation Agreement also provided for the accelerated vesting of certain share-based compensation awards for which we recognized accelerated expense of $ 0.2 million during the year ended December 31, 2019. Effective February 28, 2018, Mr. Harry Quarls retired from his position as a director and Executive Chairman of the Company. In connection with his retirement, we entered into a separation and consulting agreement (“Quarls Separation Agreement”) whereby Mr. Quarls agreed to provide transition and support services to us through December 31, 2018. We paid Mr. Quarls $ 0.3 million under the Quarls Separation Agreement. The Quarls Separation Agreement included a general release of claims and provided for the accelerated vesting of certain share-based compensation awards for which we recognized accelerated expense of $ 0.6 million during the year ended December 31, 2018. The costs associated with the Hartman and Quarls Separation Agreements, including the share-based compensation charges, were included as a component of “G&A expenses” in our Consolidated Statements of Operations for the years ended December 31, 2019 and 2018, respectively. Defined Contribution Plan We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We provide matching contributions on our employees’ elective deferral contributions up to six percent of compensation up to the maximum statutory limits. The 401(k) Plan also provides for discretionary employer contributions. The expense recognized with respect to the 401(k) Plan was $0.9 million , $0.6 million , $0.5 million for the years ended December 31, 2019 , 2018 and 2017 , respectively, and is included as a component of “General and administrative expenses” in our Statements of Operations. Amounts representing accrued obligations to the 401(k) Plan of $0.3 million and $0.3 million are included in the “Accounts payable and accrued expenses” caption on our Consolidated Balance Sheets as of December 31, 2019 and 2018 , respectively. Defined Benefit Pension and Postretirement Health Care Plans We maintain unqualified legacy defined benefit pension and defined benefit postretirement health care plans which cover a limited population of former employees that retired prior to January 1, 2000. The combined expense recognized with respect to these plans was less than $0.1 million for each year ended December 31, 2019 , 2018 and 2017 , and is included as a component of “Other, net” in our Statements of Operations. The combined unfunded benefit obligations under these plans were $1.4 million and are included within the “Accounts payable and accrued expenses” (current portion) and “Other liabilities” (noncurrent portion) captions on our Consolidated Balance Sheets as of December 31, 2019 and 2018 .

Interest Expense

Interest Expense	12 Months Ended
	Dec. 31, 2019
Banking and Thrift [Abstract]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Year Ended December 31, 2019 2018 2017 Interest on borrowings and related fees $ 36,593 $ 32,164 $ 6,995 Accretion of original issue discount 1 743 680 161 Amortization of debt issuance costs 2 2,611 2,736 1,961 Capitalized interest (4,136 ) (9,118 ) (2,725 ) $ 35,811 $ 26,462 $ 6,392 _____________________________________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 9). 2 The year ended December 31, 2017 includes a total of $0.8 million

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Earnings per Share	Earnings per Share The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Year Ended December 31, 2019 2018 2017 Net income – basic and diluted $ 70,589 $ 224,785 $ 32,662 Weighted-average shares – basic 15,110 15,059 14,996 Effect of dilutive securities 1 16 233 67 Weighted-average shares – diluted 15,126 15,292 15,063 _____________________________________________ 1

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Schedule of Policies [Line Items]
Adoption of Recently Issued Accounting Pronouncements and Comparability to Prior Periods and Recently Issued Pronouncements Pending Adoption	Adoption of Recently Issued Accounting Pronouncements and Comparability to Prior Periods Effective January 1, 2019, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) 2016–02, Leases (“ASU 2016–02”) and related amendments to accounting principles generally accepted in the United States of America (“GAAP”) which, together with ASU 2016–02, represent Accounting Standards Codification (“ASC”) Topic 842, Leases (“ASC Topic 842”). We adopted ASC Topic 842 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2019 (see Note 11 for the impact and disclosures associated with the adoption of ASC Topic 842). Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent ASC Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606). Comparative periods and related disclosures have not been restated for the application of ASC Topic 842 and ASC Topic 606. Accordingly, certain components of our Consolidated Financial Statements are not comparable between periods and the Consolidated Statement of Operations for the year ended December 31, 2017 is presented based on prior GAAP for both revenue recognition and leases in their entirety. Recently Issued Accounting Pronouncements Pending Adoption In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. We will adopt ASU 2016–13 effective January 1, 2020. While we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures, we will be applying new procedures and controls to our customer and partner billing processes in order to apply the expected loss model on a monthly basis.
Principles of Consolidation	Principles of Consolidation Our Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated.
Use of Estimates	Use of Estimates Preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these Notes. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months
Derivative Instruments	Derivative Instruments From time to time, we utilize derivative instruments to mitigate our financial exposure to commodity price and interest rate volatility. The derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, generally take the form of collars and swaps. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.
Oil and Gas Properties	Oil and Gas Properties We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”). Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (a “Ceiling Test”). The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. Depreciation, Depletion and Amortization DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.
Other Property and Equipment	Other Property and Equipment Other property and equipment consists primarily of gathering systems and related support equipment. Property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property and equipment using the straight-line balance method over the estimated useful life of each asset as follows: Gathering systems – fifteen to twenty years and Other property and equipment – three to twenty years.
Leases	Leases We determine if an arrangement is a lease at the inception of the underlying contractual arrangement. In addition, we determine whether the lease is classified as operating or financing. As of the date of adoption of ASC Topic 842 and through December 31, 2019, we do not have any financing leases. Leases are included in the captions “Other assets,” “Accounts payable and accrued liabilities” and “Other liabilities” on our Consolidated Balance Sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Notes 11 and 12. ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to 5 years , our secured incremental borrowing rate is primarily based on the rates applicable to our credit agreement (the “Credit Facility”). We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We have elected to apply a practical expedient provided in ASC Topic 842 to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term. Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we have elected to not include the underlying ROU assets and lease obligations on our Consolidated Balance Sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11. Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11.
Asset Retirement Obligations	Asset Retirement Obligations We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our Consolidated Statements of Operations.
Income Taxes	Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize tax credits and operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent they arise, as a component of interest expense and penalties as a component of income tax expense. We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.
Revenue Recognition	Revenue Recognition and Associated Costs Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through December 31, 2019, we were the agent and our midstream processing vendors were our customers with respect to all of our NGL product sales. Natural gas . Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services . We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses.
Share-Based Compensation	Share-Based Compensation Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period except for those that are based on performance which are amortized on a graded basis over the term of the applicable performance periods. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Consolidated Statements of Operations.
Revenue from Contract with Customer	Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contracts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $ 2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606.
Fair Value of Measurements	We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below. Fair value measurements are classified and disclosed in one of the following three categories: • Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value. • Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).
Fair Value, Measurements, Recurring
Schedule of Policies [Line Items]
Fair Value of Measurements	We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for WTI , LLS and MEH crude oil closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2019
Acquisitions and Divestitures [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred: Assets Oil and gas properties - proved $ 42,866 Oil and gas properties - unproved 146,686 Other property and equipment 8,642 Liabilities Revenue suspense 355 Asset retirement obligations 494 Net assets acquired $ 197,345 Cash consideration paid to Devon and tag-along parties, net $ 199,796 Application of working capital adjustments, net (2,451 ) Total consideration $ 197,345 We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt: Assets Oil and gas properties - proved $ 82,443 Oil and gas properties - unproved 16,339 Liabilities Revenue suspense 1,448 Asset retirement obligations 356 Net assets acquired $ 96,978 Cash consideration paid to Hunt, net $ 82,955 Application of working capital adjustments 245 Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate 13,778 Total acquisition costs incurred $ 96,978
Business Acquisition, Pro Forma Information	The following table presents unaudited summary pro forma financial information for the years ended December, 31, 2018 and 2017 assuming the Hunt and Devon Acquisitions and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. Year Ended December 31, 2018 2017 Total revenues $ 446,077 $ 209,015 Net income $ 227,930 $ 30,861 Net income per share - basic $ 15.14 $ 2.06 Net income per share - diluted $ 14.91 $ 2.05

Accounts Receivable and Major_2

Accounts Receivable and Major Customers (Tables)	12 Months Ended
	Dec. 31, 2019
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2019 2018 Customers $ 63,165 $ 59,030 Joint interest partners 6,929 6,404 Other 674 640 70,768 66,074 Less: Allowance for doubtful accounts (52 ) (36 ) $ 70,716 $ 66,038
Revenue from External Customers by Products and Services [Table Text Block]	Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contracts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $ 2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Positions	The following table sets forth our commodity derivative contracts as of December 31, 2019 : 1Q2020 2Q2020 3Q2020 4Q2020 1Q2021 2Q2021 3Q2021 4Q2021 NYMEX WTI Crude Swaps Average Volume Per Day (barrels) 15,648 12,648 10,630 10,630 3,333 3,297 1,630 1,630 Weighted Average Swap Price ($/barrel) $ 55.34 $ 54.96 $ 54.77 $ 54.77 $ 55.89 $ 55.89 $ 55.50 $ 55.50 NYMEX WTI Purchased Puts/Sold Calls Average Volume Per Day (barrels) 3,297 4,891 1,667 1,648 Weighted Average Purchased Put Price ($/barrel) $ 55.00 $ 55.00 $ 55.00 $ 55.00 Weighted Average Sold Call ($/barrel) $ 57.69 $ 58.42 $ 58.00 $ 58.00 NYMEX WTI Sold Puts Average Volume Per Day (barrels) 5,000 4,945 1,630 1,630 Weighted Average Sold Put Price ($/barrel) $ 44.00 $ 44.00 $ 44.00 $ 44.00 MEH Crude Swaps Average Volume Per Day (barrels) 2,000 2,000 2,000 2,000 Weighted Average Swap Price ($/barrel) $ 61.03 $ 61.03 $ 61.03 $ 61.03
Impact of Derivative Activities on Condensed Consolidated Statements of Income	The impact of our derivatives activities on income is included in the “Derivatives” caption on our Consolidated Statements of Operations. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Consolidated Statements of Cash Flows under the “Net (gains) losses” and “Cash settlements, net.” The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2019 2018 2017 Derivative gains (losses) recognized in the Consolidated Statements of Operations $ (68,131 ) $ 37,427 $ (17,819 ) Cash settlements recognized in the Consolidated Statements of Cash Flows $ (4,136 ) $ (48,291 ) $ (3,511 )
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets	The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our Consolidated Balance Sheets as of the dates presented: Fair Values December 31, 2019 December 31, 2018 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Commodity contracts Derivative assets/liabilities – current $ 4,131 $ 23,450 $ 34,932 $ 991 Commodity contracts Derivative assets/liabilities – noncurrent 2,750 3,385 10,100 — $ 6,881 $ 26,835 $ 45,032 $ 991

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Summary of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: December 31, 2019 2018 Oil and gas properties: Proved $ 1,409,219 $ 1,037,993 Unproved 53,200 63,484 Total oil and gas properties 1,462,419 1,101,477 Other property and equipment 25,915 20,383 Total property and equipment 1,488,334 1,121,860 Accumulated depreciation, depletion and amortization (367,909 ) (193,866 ) $ 1,120,425 $ 927,994

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Asset Retirement Obligations which are Included in Other Liabilities	The following table reconciles our AROs as of the dates presented, which are included in the “Other liabilities” caption on our Consolidated Balance Sheets: Year Ended December 31, 2019 2018 Balance at beginning of period $ 4,314 $ 3,286 Changes in estimates (2 ) 354 Liabilities incurred 290 335 Liabilities settled (67 ) (8 ) Acquisitions of properties 83 385 Sale of properties — (310 ) Accretion expense 316 272 Balance at end of period $ 4,934 $ 4,314

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Carrying Amount of Components of Long-term Debt	The following table summarizes our long-term debt as of the dates presented: December 31, 2019 December 31, 2018 Principal Unamortized Discount and Issuance Costs 1 Principal Unamortized Discount and Issuance Costs 1 Credit facility 2 $ 362,400 $ 321,000 Second lien term loan 200,000 $ 7,372 200,000 $ 9,625 Totals 562,400 7,372 521,000 9,625 Less: Unamortized discount (2,415 ) (3,159 ) Less: Unamortized deferred issuance costs (4,957 ) (6,466 ) Long-term debt, net $ 555,028 $ 511,375

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Summary of Provision for Income Taxes from Continuing Operations	The following table summarizes our provision for income taxes for the periods presented: Year Ended December 31, 2019 2018 2017 Current income taxes (benefit) Federal $ (1,236 ) $ (2,471 ) $ — (1,236 ) (2,471 ) — Deferred income taxes (benefit) Federal 1,236 2,471 (4,943 ) State 2,137 523 — 3,373 2,994 (4,943 ) $ 2,137 $ 523 $ (4,943 )
Income Taxes Reconciliation	The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our income (loss) before income taxes and our reported income tax benefit for the periods presented: Year Ended December 31, 2019 2018 2017 Computed at federal statutory rate $ 15,272 21.0 % $ 47,315 21.0 % $ 9,701 35.0 % State income taxes, net of federal income tax benefit 1,494 2.1 % 1,743 0.8 % (1,383 ) (5.0 )% Change in valuation allowance (14,240 ) (19.6 )% (48,820 ) (21.7 )% (24,353 ) (87.8 )% Effect of rate change on the valuation allowance — — % — — % (86,612 ) (312.5 )% Effect of rate change — — % — — % 86,612 312.5 % Reorganization adjustments — — % — — % 10,760 38.8 % Other, net (389 ) (0.5 )% 285 0.1 % 332 1.2 % $ 2,137 3.0 % $ 523 0.2 % $ (4,943 ) (17.8 )%
Summary of Principal Components of Net Deferred Income Tax Liability	The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented: December 31, 2019 2018 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 175,221 $ 163,437 Alternative minimum tax (“AMT”) credit carryforwards 1,236 2,471 Asset retirement obligations 1,073 647 Pension and postretirement benefits 340 441 Share-based compensation 880 546 Fair value of derivative instruments 4,191 — Interest expense limitation 11,463 3,128 Other 2,441 2,590 196,845 173,260 Less: Valuation allowance (114,939 ) (128,650 ) Total net deferred tax assets 81,906 44,610 Deferred tax liabilities: Property and equipment 83,330 33,413 Fair value of derivative instruments — 9,248 Total deferred tax liabilities 83,330 42,661 Net deferred tax assets (liabilities) $ (1,424 ) $ 1,949

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of Supplemental Balance Sheet Information Related to Leases [Table Text Block]	The following table summarizes supplemental balance sheet information related to leases as of December 31, 2019 : ROU assets - operating leases $ 2,740 Current operating lease obligations $ 847 Noncurrent operating lease obligations 2,232 Total operating lease obligations $ 3,079 Weighted-average remaining lease term Operating leases 4.1 Years Weighted-average discount rate Operating leases 5.97 % Maturities of operating lease obligations for the years ending December 31, 2020 $ 847 2021 830 2022 834 2023 833 2024 139 Total undiscounted lease payments 3,483 Less: imputed interest (404 ) Total operating lease obligations $ 3,079
Schedule of Supplemental Cash Flow Information Related to Leases [Table Text Block]	The following table summarizes supplemental cash flow information, as determined in accordance with ASC Topic 842, related to leases for the twelve months ended December 31, 2019 : Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 659 ROU assets obtained in exchange for lease obligations: Operating leases 1 $ 3,325 ___________________ 1 Includes $ 2.5 million recognized upon adoption of ASC Topic 842 and $ 0.8 million obtained during the twelve months ended December 31, 2019 .
Lease, Cost [Table Text Block]	The following table summarizes the components of our total lease cost, as determined in accordance with ASC Topic 842, for the twelve months ended December 31, 2019 : Operating lease cost $ 773 Short-term lease cost 36,202 Variable lease cost 23,762 Less: Amounts charged as drilling costs 1 (33,354 ) Total lease cost recognized in the Condensed Consolidated Statement of Operations 2 $ 27,383 ___________________ 1 Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs. 2 Includes $ 12.1 million recognized in Gathering, processing and transportation, $ 14.5 million recognized in Lease operating and $ 0.8 million recognized in G&A for the twelve months ended December 31, 2019 .

Additional Balance Sheet Deta_2

Additional Balance Sheet Detail (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2019 2018 Other current assets: Tubular inventory and well materials $ 2,989 $ 4,061 Prepaid expenses 1,469 1,064 $ 4,458 $ 5,125 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 3,952 $ 2,437 Right-of-use assets - operating leases 2,740 — Other 32 44 $ 6,724 $ 2,481 Accounts payable and accrued liabilities: Trade accounts payable $ 30,098 $ 16,507 Drilling costs 18,832 22,434 Royalties 44,537 51,212 Production, ad valorem and other taxes 3,244 2,418 Compensation and benefits 5,272 4,489 Interest 730 670 Current operating lease obligations 847 — Other 2,264 5,970 $ 105,824 $ 103,700 Other liabilities: Asset retirement obligations $ 4,934 $ 4,314 Noncurrent operating lease obligations 2,232 — Defined benefit pension obligations 873 857 Postretirement health care benefit obligations 343 362 $ 8,382 $ 5,533

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following tables summarize the valuation of those assets and (liabilities) as of the dates presented: As of December 31, 2019 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 4,131 $ — $ 4,131 $ — Commodity derivative assets – noncurrent 2,750 — 2,750 — Liabilities: Commodity derivative liabilities – current $ (23,450 ) $ — $ (23,450 ) $ — Commodity derivative liabilities – noncurrent (3,385 ) — (3,385 ) — As of December 31, 2018 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 34,932 $ — $ 34,932 $ — Commodity derivative assets – noncurrent 10,100 — 10,100 — Liabilities: Commodity derivative liabilities – current $ (991 ) $ — $ (991 ) $ — Commodity derivative liabilities – noncurrent — — — —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Loss Contingencies by Contingency	The following table sets forth our significant commitments as of December 31, 2019 , by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Other Commitments 2020 $ 12,962 $ 289 2021 12,962 140 2022 12,962 70 2023 12,962 — 2024 12,962 — Thereafter 37,789 — Total $ 102,599 $ 499

Share-Based Compensation and _2

Share-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Activity of Awarded Restricted Stock Units	The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs: Restricted Stock Units Weighted-Average Grant Date Fair Value Balance at beginning of year 208,040 $ 47.35 Granted 13,175 $ 30.35 Vested (74,888 ) $ 39.40 Forfeited (9,451 ) $ 51.71 Balance at end of year 136,876 $ 49.76
Performance Restricted Stock Units [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Equity Instruments Other than Options, Valuation Assumptions	The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2019 and 2017 are presented as follows: 2019 2017 Expected volatility 49.9 % 59.63% to 62.18% Dividend yield 0.0% 0.0% Risk-free interest rate 1.66 % 1.44% to 1.51%
Activity of Awarded Performance-based RSUs	The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Units Weighted-Average Grant Date Fair Value Balance at beginning of year 89,071 $ 58.69 Granted 15,066 $ 34.02 Vested (3,917 ) $ 63.25 Forfeited (1,083 ) $ 63.25 Expired (19,223 ) $ 62.92 Balance at end of year 79,914 $ 52.73

Interest Expense (Tables)

Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2019
Banking and Thrift [Abstract]
Components of Interest Expense	The following table summarizes the components of interest expense for the periods presented: Year Ended December 31, 2019 2018 2017 Interest on borrowings and related fees $ 36,593 $ 32,164 $ 6,995 Accretion of original issue discount 1 743 680 161 Amortization of debt issuance costs 2 2,611 2,736 1,961 Capitalized interest (4,136 ) (9,118 ) (2,725 ) $ 35,811 $ 26,462 $ 6,392 _____________________________________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 9). 2 The year ended December 31, 2017 includes a total of $0.8 million

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Components of Calculation of Basic and Diluted Earnings Per Share	The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Year Ended December 31, 2019 2018 2017 Net income – basic and diluted $ 70,589 $ 224,785 $ 32,662 Weighted-average shares – basic 15,110 15,059 14,996 Effect of dilutive securities 1 16 233 67 Weighted-average shares – diluted 15,126 15,292 15,063 _____________________________________________ 1

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019
Maximum [Member]
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	5 years
Maximum [Member] | Gathering systems
Property, Plant and Equipment [Line Items]
Useful life	20 years
Maximum [Member] | Other property and equipment
Property, Plant and Equipment [Line Items]
Useful life	20 years
Minimum [Member]
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	2 years
Minimum [Member] | Gathering systems
Property, Plant and Equipment [Line Items]
Useful life	15 years
Minimum [Member] | Other property and equipment
Property, Plant and Equipment [Line Items]
Useful life	3 years

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Lessee, Lease, Description (Details)	Dec. 31, 2019
Maximum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	5 years
Minimum [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	2 years

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Detail) $ / shares in Units, $ in Thousands	Jul. 31, 2018USD ($)	Mar. 01, 2018USD ($)	Jul. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)a	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)a$ / shares	Sep. 29, 2017a
Significant Acquisitions and Disposals
Capitalized Costs, Proved Properties						$ 2,400			$ 4,100	$ 3,700	$ 2,400
Second Lien Facility									200,000	200,000
Property, Plant and Equipment, Gross									1,488,334	1,121,860
Asset Retirement Obligation						$ 3,286			4,934	4,314	$ 3,286
Cash Received for Suspended Revenues Attributable to Acquired Properties		$ 355
Mid-Continent Divestiture [Member]
Significant Acquisitions and Disposals
Proceeds from Sale of Oil and Gas Property and Equipment	$ 6,200								6,000
Cash Paid to Buyer in Connection with Final Settlement									500
Cash Paid for Suspended Revenues in Connection with FInal Settlement									200
Asset Retirement Obligation									300
Working Capital Adjustments, Net	1,300		$ 1,300
Pre-Tax Operating Income Attributable to Assets Sold					$ (1,600)		$ (2,200)
Undeveloped Acreage [Member]
Significant Acquisitions and Disposals
Proceeds from Sale of Oil and Gas Property and Equipment									1,700
Working Interests Acquisition [Member] [Domain]
Significant Acquisitions and Disposals
Cash Paid on Date of Acquisition									6,500
Hunt Acquisition [Member]
Significant Acquisitions and Disposals
Capitalized Costs, Proved Properties		82,443
Area of Land | a						9,700					9,700
Other Payments to Acquire Businesses									86,000
Cash Paid on Date of Acquisition		83,000
Accumulated Costs, net of suspended revenues, for wells in which Hunt elected not to participate		13,778
Business Acquisition, Transaction Costs		96,978		$ 400		$ 100			500		$ 100
Capitalized Costs, Proved Properties		16,339
Asset Retirement Obligation		356
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		96,978
Working Capital Adjustments, Net	$ (245)		(245)
Cash Received for Suspended Revenues Attributable to Acquired Properties			$ 1,448
Net Cash Paid on Date of Acquisition		82,955
Devon Acquisition [Member]
Significant Acquisitions and Disposals
Business Acquisition, Revenue Reported by Acquired Entity since Acquisition Date				400		9,000
Business Acquisition, Pro Forma Revenue										446,077	209,015
Capitalized Costs, Proved Properties		42,866
Acreage, Net | a												19,600
Other Payments to Acquire Businesses									205,000	199,800	200,900
Cash Paid on Date of Acquisition		199,796
Business Acquisition, Transaction Costs									$ 1,300
Capitalized Costs, Proved Properties		146,686
Property, Plant and Equipment, Gross		8,642
Asset Retirement Obligation		494
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		197,345
Working Capital Adjustments, Net		(2,451)
Preliminary Purchase Price		$ 197,345
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax										$ 227,930	$ 30,861
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares										$ 15.14	$ 2.06
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares										$ 14.91	$ 2.05
Cash Received for Suspended Revenues Attributable to Acquired Properties								$ 1,100
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual				$ 200		$ 4,000

Accounts Receivable and Major_3

Accounts Receivable and Major Customers - Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of Goods and Services Sold		$ 23,197	$ 18,626	$ 10,734
Net Income (Loss) Available to Common Stockholders, Basic	$ 32,662	70,589	224,785
Customers		63,165	59,030
Joint interest partners		6,929	6,404
Other		674	640
Accounts Receivable, Gross, Current, Total		70,768	66,074
Less: Allowance for doubtful accounts		(52)	(36)
Accounts receivable, net of allowance for doubtful accounts		70,716	66,038
Oil and Gas, Exploration and Production [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		434,713	402,485	140,886
Oil and Condensate [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		16,589	21,073	10,066
Natural Gas, Production [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		$ 17,733	$ 15,972	$ 8,517

Accounts Receivable and Major_4

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Customer	Dec. 31, 2018USD ($)Customer
Accounts, Notes, Loans and Financing Receivable [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		$ 2,700
Customers	$ 63,165	$ 59,030
Accounts Receivable | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	4	3
Revenues, major customers	$ 354,600	$ 304,300
Concentration risk, percentage	76.00%	69.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 172,300	$ 173,000
Concentration risk, percentage	37.00%	39.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 84,600	$ 71,500
Concentration risk, percentage	18.00%	16.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 50,700	$ 59,800
Concentration risk, percentage	11.00%	14.00%
Accounts Receivable | Customer Concentration Risk | Major Customer Four [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 47,000
Concentration risk, percentage	10.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	70.00%	48.00%
Accounts receivable, major customers	$ 44,500	$ 28,600

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)bblEntity$ / bbl	Feb. 21, 2020USD ($)$ / bbl	Jan. 31, 2020bbl	Dec. 31, 2018USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Asset | $	$ 6,881			$ 45,032
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Asset | $	$ 20,000
Number Of Derivative Counterparty | Entity	9
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Underlying Basis	WTI
Commodity contracts | Louisiana Light Sweet [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Underlying Basis	LLS
Commodity contracts | MEH [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Underlying Basis	MEH
Subsequent Event [Member] | Costless collar [Domain] | Natural Gas [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Nonmonetary Notional Amount		270,000
Derivative, Floor Price		2
Derivative, Cap Price		2.18
Subsequent Event [Member] | Interest Rate Contract [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Notional Amount | $		$ 300,000
Derivative, Average Fixed Interest Rate		136.00%
First Quarter 2020 [Member] | Swap [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	15,648
Derivative, Floor Price	48
Derivative, Cap Price	57.10
First Quarter 2020 [Member] | Swap [Member] | MEH [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,000
First Quarter 2020 [Member] | Subsequent Event [Member] | Swap [Member] | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Nonmonetary Notional Amount | bbl			2,000

Commodity Derivative Positions

Commodity Derivative Positions (Detail)	Dec. 31, 2019bbl$ / bbl
Fourth Quarter 2021 [Member] [Domain] | Put Option [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	44
Derivative, Nonmonetary Notional Amount | bbl	1,630
Fourth Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	55.50
Derivative, Nonmonetary Notional Amount | bbl	1,630
Third Quarter 2021 [Member] [Domain] | Put Option [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	44
Derivative, Nonmonetary Notional Amount | bbl	1,630
Third Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	55.50
Derivative, Nonmonetary Notional Amount | bbl	1,630
Second Quarter 2021 [Member] [Domain] | 3-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	55
Derivative, Cap Price	58
Derivative, Nonmonetary Notional Amount | bbl	1,648
Second Quarter 2021 [Member] [Domain] | Put Option [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	44
Derivative, Nonmonetary Notional Amount | bbl	4,945
Second Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	55.89
Derivative, Nonmonetary Notional Amount | bbl	3,297
First Quarter 2021 [Member] [Domain] | 3-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	55
Derivative, Cap Price	58
Derivative, Nonmonetary Notional Amount | bbl	1,667
First Quarter 2021 [Member] [Domain] | Put Option [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	44
Derivative, Nonmonetary Notional Amount | bbl	5,000
First Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	55.89
Derivative, Nonmonetary Notional Amount | bbl	3,333
Fourth Quarter 2020 [Member] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	54.77
Derivative, Nonmonetary Notional Amount | bbl	10,630
Fourth Quarter 2020 [Member] | Swap [Member] | MEH [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	61.03
Derivative, Nonmonetary Notional Amount | bbl	2,000
Third Quarter 2020 [Member] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	55
Derivative, Cap Price	58.42
Derivative, Nonmonetary Notional Amount | bbl	4,891
Third Quarter 2020 [Member] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	54.77
Derivative, Nonmonetary Notional Amount | bbl	10,630
Third Quarter 2020 [Member] | Swap [Member] | MEH [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	61.03
Derivative, Nonmonetary Notional Amount | bbl	2,000
Second Quarter 2020 [Member] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	55
Derivative, Cap Price	57.69
Derivative, Nonmonetary Notional Amount | bbl	3,297
Second Quarter 2020 [Member] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	54.96
Derivative, Nonmonetary Notional Amount | bbl	12,648
Second Quarter 2020 [Member] | Swap [Member] | MEH [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	61.03
Derivative, Nonmonetary Notional Amount | bbl	2,000
First Quarter 2020 [Member] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	48
Derivative, Cap Price	57.10
Derivative, Swap Type, Fixed Price	55.34
Derivative, Nonmonetary Notional Amount | bbl	15,648
First Quarter 2020 [Member] | Swap [Member] | MEH [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Fixed Price	61.03
Derivative, Nonmonetary Notional Amount | bbl	2,000

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gains (losses) recognized in the Consolidated Statements of Operations	$ (68,131)	$ 37,427	$ (17,819)
Cash settlements recognized in the Consolidated Statements of Cash Flows	$ (4,136)	$ (48,291)	$ (3,511)

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivatives	$ (68,131)	$ 37,427	$ (17,819)
Derivative assets, current	4,131	34,932
Derivative assets, noncurrent	2,750	10,100
Derivative liabilities, noncurrent	3,385	0
Derivative Asset	6,881	45,032
Derivative liabilities, current	23,450	991
Derivative liabilities	26,835	991
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Asset	20,000
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	4,131	34,932
Derivative liabilities, current	23,450	991
Commodity contracts | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	2,750	10,100
Derivative liabilities, noncurrent	3,385	0
Fair Value, Measurements, Recurring | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets, current	4,131	34,932
Derivative assets, noncurrent	2,750	10,100
Derivative liabilities, noncurrent	3,385	0
Derivative liabilities, current	$ (23,450)	$ (991)

Summary of Property and Equipme

Summary of Property and Equipment (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)
Property, Plant and Equipment [Abstract]
Proved Oil and Gas Property, Full Cost Method	$ 1,409,219	$ 1,037,993
Undeveloped Leasehold Costs Transferred	16,800	82,800
Interest Costs Capitalized	$ 4,100	$ 9,100	$ 2,700
Amortization Expense Per Physical Unit of Production | $ / bbl	17.25	16.11	12.87
Unproved Oil and Gas Property excluded	$ 53,200	$ 63,500
Capitalized Exploratory Well Costs		300
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	1,300	6,100	$ 43,100	$ 2,700
Capitalized Costs, Proved Properties	4,100	3,700	$ 2,400
Oil and gas properties:
Unproved Oil and Gas Property, Full Cost Method	53,200	63,484
Oil and Gas Property, Full Cost Method, Gross	1,462,419	1,101,477
Other property and equipment	25,915	20,383
Total property and equipment	1,488,334	1,121,860
Accumulated depreciation, depletion and amortization	(367,909)	(193,866)
Property and equipment, net (successful efforts method)	$ 1,120,425	$ 927,994

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligations which are Included in Other Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 4,314	$ 3,286
Changes in estimates	(2)	354
Liabilities incurred	290	335
Liabilities settled	(67)	(8)
Acquisitions of properties	(83)	(385)
Asset Retirement Obligation, Sale of Properties	0	(310)
Accretion expense	316	272
Balance at end of period	$ 4,934	$ 4,314

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Amortization of debt issuance costs 2	$ 1,961	$ 2,611	$ 2,736
Credit facility 2		362,400	321,000
Second Lien Facility		200,000	200,000
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums		7,372	9,625
Debt Instrument, Unamortized Discount		(2,415)	(3,159)
Unamortized Debt Issuance Expense		(4,957)	(6,466)
Long-term Debt		562,400	521,000
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net		$ 555,028	$ 511,375
Second Lien Facility [Member]
Debt Instrument [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		7.00%
Second Lien Facility, Interest Rate		8.81%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 03, 2019
Debt Disclosure [Line Items]
Interest on borrowings and related fees	$ 6,995	$ 36,593	$ 32,164
Amortization of debt issuance costs 2	1,961	2,611	2,736
Interest Paid, Capitalized, Investing Activities	(2,725)	(4,136)	(9,118)
Interest Expense	$ 6,392	35,811	26,462	$ 6,392
Debt Issuance Costs, Line of Credit Arrangements, Gross		$ 2,600	900
Line of credit, redetermination period		6 months
Write off of Deferred Debt Issuance Cost				$ 800
Line of credit , extension period		91 days
Required covenant, current ratio		1
Term of credit facility		5 years
Second Lien Facility		$ 200,000	$ 200,000
Proceeds from Debt, Net of Issuance Costs		187,800
Debt Instrument, Unamortized Discount		4,000
Unamortized Debt Issuance Expense		$ 8,200
Debt Instrument, Discounted Percentage		98.00%
Revolving Credit Facility [Member]
Debt Disclosure [Line Items]
Maximum borrowing capacity		$ 500,000			$ 1,000,000
Line of Credit Facility, Interest Rate at Period End		3.75%
Required covenant, debt to EBITDAX ratio		4
Revolving Credit Facility [Member] | Minimum [Member]
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		0.50%
Revolving Credit Facility [Member] | Maximum [Member]
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		1.50%
Credit facility interest rate option two, applicable margin rate		2.50%
Revolving credit facility
Debt Disclosure [Line Items]
Letter of credit amount outstanding		$ 400
Revolving credit facility | Letter of Credit
Debt Disclosure [Line Items]
Maximum borrowing capacity		$ 25,000
Letter of Credit | Minimum [Member]
Debt Disclosure [Line Items]
Commitment fees for undrawn credit facility		0.375%
Letter of Credit | Maximum [Member]
Debt Disclosure [Line Items]
Commitment fees for undrawn credit facility		0.50%
Second Lien Facility [Member]
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		7.00%
Credit facility interest rate option two, applicable margin rate		6.00%
Second Lien Facility, Initial Interest Rate		8.34%
Second Lien Facility, Effective Interest Rate		9.89%
Year 3 [Member]
Debt Disclosure [Line Items]
Prepayment Premium		101.00%
Prepayment Premium, Change in Control		101.00%

Summary of Provision for Income

Summary of Provision for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal	$ (1,236)	$ (2,471)	$ 0
Current income tax expense (benefit), total	(1,236)	(2,471)	0
Federal	1,236	2,471	(4,943)
State	2,137	523	0
Deferred income tax benefit, total	3,373	2,994	(4,943)
Income tax benefit	$ 2,137	$ 523	$ (4,943)

Income Taxes Reconciliation (De

Income Taxes Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Computed at federal statutory rate	$ 15,272	$ 47,315	$ 9,701
State income taxes, net of federal income tax benefit	(1,494)	(1,743)	1,383
Change in valuation allowance	(14,240)	(48,820)	(24,353)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	0	86,612
Effective Income Tax Rate Reconciliation, Reorganization Adjustments, Amount	0	0	10,760
Other, net	(389)	285	332
Income tax benefit	$ 2,137	$ 523	$ (4,943)
Effective Income Tax Rate Reconciliation, Percent	3.00%	0.20%	(17.80%)
Computed at federal statutory rate	21.00%	21.00%	35.00%
State income taxes, net of federal income tax benefit	2.10%	0.80%	(5.00%)
Change in valuation allowance	(19.60%)	(21.70%)	(87.80%)
Effective Income Tax Rate Reconciliation, Effect of rate change on valuation allowance, Amount	$ 0	$ 0	$ (86,612)
Effective Income Tax Rate Reconciliation, Effect of rate change on valuation allowance, Percent	0.00%	0.00%	(312.50%)
Effect of rate change	0.00%	0.00%	312.50%
Reorganization adjustments	0.00%	0.00%	38.80%
Other, net	(0.50%)	0.10%	1.20%

Summary of Principal Components

Summary of Principal Components of Net Deferred Income Tax Liability (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	$ 1,073	$ 647
Deferred Tax Assets, Operating Loss Carryforwards	175,221	163,437
Deferred tax assets:
Less: Valuation allowance	(114,939)	(128,650)
Total net deferred tax assets	81,906	44,610
Deferred income taxes	0	1,949
Deferred Tax Liabilities, Property, Plant and Equipment	83,330	33,413
Deferred Tax Liabilities, Derivatives	0	9,248
Deferred Tax Liabilities, Net	83,330	42,661
Deferred Tax Liabilities, Net, Noncurrent	(1,424)	0
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	1,236	2,471
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Postretirement Benefits	340	441
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	880	546
Deferred Tax Assets, Derivative Instruments	4,191	0
Deferred Tax Asset, Interest Carryforward	11,463	3,128
Deferred Tax Assets, Other	2,441	2,590
Deferred Tax Assets, Gross	$ 196,845	$ 173,260

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Valuation Allowance [Line Items]
Computed at federal statutory rate	21.00%	21.00%	35.00%
Income taxes receivable	$ 1,236	$ 2,471
State	2,137	523	$ 0
Other, net	(389)	285	332
Liabilities for unrecognized tax benefits	0	0
Deferred Tax Assets, Valuation Allowance	114,939	128,650
Income Tax Examination, Penalties and Interest Expense	$ 0	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Percent	3.00%	0.20%	(17.80%)
Deferred Tax Assets, Tax Credit Carryforwards	$ 1,200
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	0	$ 0	$ 86,612
Federal
Valuation Allowance [Line Items]
Operating Loss Carryforwards	613,400
State and Local Jurisdiction
Valuation Allowance [Line Items]
Operating Loss Carryforwards	$ 437,900
Federal, State and Local Tax Jurisdictions
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance		$ 114,900

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Operating Lease, Payments			$ 659
Operating Lease, Cost			773
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 800	$ 2,500	3,325
Lease, Cost			27,383
Short-term Lease, Cost			36,202
Variable Lease, Cost			23,762
Amounts charged as dilling costs			(33,354)
Operating Lease, Liability, Current	847		847	$ 0
Operating Lease, Liability, Noncurrent	$ 2,232		$ 2,232	0
Operating Lease, Weighted Average Remaining Lease Term	4 years 1 month 6 days		4 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent	5.97%		5.97%
Lessee, Operating Lease, Liability, Payments, Due Year Two	$ 847		$ 847
Lessee, Operating Lease, Liability, Payments, Due Year Three	830		830
Lessee, Operating Lease, Liability, Payments, Due Year Four	834		834
Lessee, Operating Lease, Liability, Payments, Due Year Five	833		833
Lessee, Operating Lease, Liability, Payments, Due after Year Five	139		139
Lessee, Operating Lease, Liability, Payments, Due	3,483		3,483
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(404)		(404)
Operating Lease, Right-of-Use Asset	2,740	2,500	2,740	0
Operating Lease, Liability	$ 3,079	$ 2,800	3,079
Operating Leases, Rent Expense, Net				$ 2,700	$ 1,000
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost			12,100
Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost			14,500
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost			$ 800

Components of Selected Balance

Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2018
Other current assets:
Tubular inventory and well materials	$ 2,989		$ 4,061
Prepaid expenses	1,469		1,064
Other current assets	4,458		5,125
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	3,952		2,437
Operating Lease, Right-of-Use Asset	2,740	$ 2,500	0
Other	32		44
Accounts payable and accrued liabilities:
Trade accounts payable	30,098		16,507
Drilling costs	18,832		22,434
Royalties	44,537		51,212
Production, ad valorem and other taxes	3,244		2,418
Compensation-related	5,272		4,489
Interest	730		670
Operating Lease, Liability, Current	847		0
Other	2,264		5,970
Other liabilities:
Asset retirement obligations	4,934		4,314
Operating Lease, Liability, Noncurrent	2,232		0
Liability, Defined Benefit Pension Plan, Noncurrent	873		857
Postretirement health care benefit obligations	$ 343		$ 362

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Assets:
Commodity derivative assets – current	$ 4,131	$ 34,932
Derivative assets	2,750	10,100
Liabilities:
Derivative liabilities, current	23,450	991
Derivative liabilities, noncurrent	(3,385)	0
Fair Value, Measurements, Recurring | Commodity contracts
Assets:
Commodity derivative assets – current	4,131	34,932
Derivative assets	2,750	10,100
Liabilities:
Derivative liabilities, current	(23,450)	(991)
Derivative liabilities, noncurrent	(3,385)	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Assets:
Commodity derivative assets – current	0	0
Derivative assets	0	0
Liabilities:
Derivative liabilities, current	0	0
Derivative liabilities, noncurrent	0	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Assets:
Commodity derivative assets – current	4,131	34,932
Derivative assets	2,750	10,100
Liabilities:
Derivative liabilities, current	(23,450)	(991)
Derivative liabilities, noncurrent	(3,385)	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Assets:
Commodity derivative assets – current	0	0
Derivative assets	0	0
Liabilities:
Derivative liabilities, current	0	0
Derivative liabilities, noncurrent	$ 0	$ 0
Crude Oil | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Underlying Basis	WTI
Louisiana Light Sweet [Member] | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Underlying Basis	LLS
MEH [Domain] | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Underlying Basis	MEH

Significant Commitments by Cate

Significant Commitments by Category (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Gathering and Intermediate Transportation
Commitments
2020	$ 12,962
2021	12,962
2022	12,962
2023	12,962
2024	12,962
Thereafter	37,789
Total	102,599
Other Commitments
Commitments
2020	289
2021	140
2022	70
2023	0
2024	0
Thereafter	0
Total	$ 499

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Thousands	Jan. 01, 2020bbl	Dec. 31, 2019USD ($)bbl	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Line Items]
Commitment length		5 years
Number of drilling rigs		2
Minimum commitment | bbl		8,000
Estimated Litigation Liability, Current		$ 300
Asset retirement obligations		4,934	$ 4,314	$ 3,286
Environmental Compliance
Commitments and Contingencies Disclosure [Line Items]
Asset retirement obligations		4,900
Gathering and Intermediate Transportation
Commitments and Contingencies Disclosure [Line Items]
Contractual Commitments Future Minimum Payments Due		102,599
Contractual Commitments Future Minimum Payments Due Current		$ 12,962
Subsequent Event [Member]
Commitments and Contingencies Disclosure [Line Items]
Term of drilling rig agreement	1 year
Period to give notice to termination drilling rig agreement	30 days
Minimum commitment | bbl	0

Shareholders' Equity - Addition

Shareholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 13, 2016
Equity [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, shares issued	15,135,598	15,080,594
Common stock, par value	$ 0.01	$ 0.01		$ 0.01
Change in pension and postretirement obligations, net of tax	$ (141)	$ 82	$ (73)
Common stock, shares authorized	45,000,000	45,000,000

Share-Based Compensation and _3

Share-Based Compensation and Other Benefit Plans - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 12, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Separation Agreement, Consulting Fees				$ 300
Share-based Payment Arrangement, Accelerated Cost			$ 200	600
Share-based compensation (equity-classified)	$ (3,800)		(4,082)	(4,618)	$ (3,809)
Defined Contribution Plan, Cost			900	600	$ 500
Compensation			$ 5,272	4,489
Time Vested Restricted Stock Units [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			360,615
Performance Restricted Stock Units [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period			3 years
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			15,066		98,526
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized			113,592
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			15,066
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 34.02
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			5 years
Performance Restricted Stock Units [Domain] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares expected to vest at grant date			0.00%
Performance Restricted Stock Units [Domain] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares expected to vest at grant date			200.00%
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 1 month 6 days
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount			$ 5,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			13,175
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 30.35
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value			$ 3,000	3,300	$ 800
Share-based Payment Arrangement, Tranche One [Member] | Performance Restricted Stock Units [Domain] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value					$ 47.70
Share-based Payment Arrangement, Tranche One [Member] | Performance Restricted Stock Units [Domain] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 34.02		$ 65.28
Other Pension, Postretirement and Supplemental Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		$ 100	$ 100		$ 100
Liability, Defined Benefit Plan, Noncurrent			$ 1,400	1,400
Pension Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay			6.00%
Compensation			$ 300	$ 300
Employees and Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			1,424,600

Share-Based Compensation and _4

Share-Based Compensation and Other Benefit Plans (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 12, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Severance Costs			$ 500
Share-based Payment Arrangement, Accelerated Cost			200	$ 600
Defined Contribution Plan, Cost			900	600	$ 500
Share-based compensation (equity-classified)	$ 3,800		4,082	4,618	3,809
Restricted Stock Units (RSUs)
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount			$ 5,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			13,175
Stock Options
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 1 month 6 days
Other Pension, Postretirement and Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Liability, Defined Benefit Plan, Noncurrent			$ 1,400	$ 1,400
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		$ 100	$ 100		$ 100

Share-Based Compensation and _5

Share-Based Compensation and Other Benefit Plans - Fair Value of Each Award Estimated on Date of Grant Using Black-Scholes-Merton Option-Pricing Formula (Detail) - Performance Restricted Stock Units [Domain]	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2017
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Expected volatility, min		59.63%
Expected volatility, max	49.90%	62.18%
Dividend yield	0.00%	0.00%
Risk-free interest rate, min		1.44%
Risk-free interest rate, max	1.66%	1.51%

Share-Based Compensation and _6

Share-Based Compensation and Other Benefit Plans - Activity of Awarded Restricted Stock Units (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Units (RSUs)
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 3	$ 3.3	$ 0.8
Number of shares
Balance at beginning of year (in shares)	208,040
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	13,175
Vested (in shares)	(74,888)
Forfeited (in shares)	(9,451)
Balance at end of year (in shares)	136,876	208,040
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 47.35
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	30.35
Vested (in dollars per share)	39.40
Forfeited (in dollars per share)	51.71
Balance at end of year (in dollars per share)	$ 49.76	$ 47.35
Performance Restricted Stock Units [Domain]
Number of shares
Balance at beginning of year (in shares)	89,071
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	15,066
Vested (in shares)	(3,917)
Forfeited (in shares)	(1,083)
Balance at end of year (in shares)	79,914	89,071
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 58.69
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	34.02
Vested (in dollars per share)	63.25
Forfeited (in dollars per share)	63.25
Balance at end of year (in dollars per share)	$ 52.73	$ 58.69
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures and Expirations	19,223
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Intrinsic Value	$ 62.92
Minimum [Member] | Performance Restricted Stock Units [Domain]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	0.00%
Maximum [Member] | Performance Restricted Stock Units [Domain]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	200.00%

Components of Interest Expense

Components of Interest Expense (Detail) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Banking and Thrift [Abstract]
Interest expense	$ 6,392	$ 35,811	$ 26,462	$ 6,392
Capitalized interest	(2,725)	(4,136)	(9,118)
Amortization of debt issuance costs 2	1,961	2,611	2,736
Amortization of Debt Discount (Premium)	161	743	680
Interest on borrowings and related fees	$ 6,995	$ 36,593	$ 32,164
Write off of Deferred Debt Issuance Cost				$ 800

Components of Calculation of Ba

Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands, $ in Thousands		4 Months Ended	12 Months Ended
		Dec. 31, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net loss attributable to common shareholders		$ 32,662	$ 70,589	$ 224,785
Weighted-average shares – basic		14,996	15,110	15,059	14,996
Effect of dilutive securities	[1]	67	16	233
Weighted-average shares – diluted		15,063	15,126	15,292	15,063
[1]	Represents a combination of unvested RSUs and PRSUs that are dilutive with the exception of December 31, 2019 at which time all of our unvested PRSUs were determined to be at a zero percent vesting level due to the relative performance of our common stock.

Uncategorized Items - pva-20191

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (94,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(2,659,000)
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(2,659,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (94,000)