Ranger Oil (ROCC) 10-K 9 Mar 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 05, 2021
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float	$ 144,297,933
Documents Incorporated by Reference	Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0000077159
ICFR Auditor Attestation Flag	true
Current Fiscal Year End Date	--12-31
Common Stock
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		15,266,598
Series A Preferred Stock
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		225,481.09

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues
Gain (Loss) on Disposition of Property Plant Equipment	$ 18,000	$ 5,000	$ (177,000)
Total revenues	273,268,000	471,216,000	440,832,000
Operating expenses
Lease operating	37,463,000	43,088,000	35,879,000
Cost of Goods and Services Sold	22,050,000	23,197,000	18,626,000
Production and ad valorem taxes	16,619,000	28,057,000	23,547,000
General and administrative	33,789,000	25,484,000	26,064,000
Depreciation, depletion and amortization	140,673,000	174,569,000	127,961,000
Asset Impairment Charges	391,849,000	0	0
Total operating expenses	642,443,000	294,395,000	232,077,000
Operating income (loss)	(369,175,000)	176,821,000	208,755,000
Other income (expense)
Interest expense, net of amounts capitalized	(31,257,000)	(35,811,000)	(26,462,000)
Derivatives	88,422,000	(68,131,000)	37,427,000
Other, net	(850,000)	(153,000)	2,266,000
Reorganization items, net	0	0	3,322,000
Income (loss) before income taxes	(312,860,000)	72,726,000	225,308,000
Income Tax Expense (Benefit)	2,303,000	(2,137,000)	(523,000)
Net Income (Loss) Available to Common Stockholders, Basic	$ (310,557,000)	$ 70,589,000	$ 224,785,000
Net income (loss) per share:
Basic (in dollars per share)	$ (20.46)	$ 4.67	$ 14.93
Diluted (in dollars per share)	$ (20.46)	$ 4.67	$ 14.70
Weighted average shares outstanding – basic	15,176	15,110	15,059
Weighted average shares outstanding – diluted	15,176	15,126	15,292
Oil and Gas, Exploration and Production [Member]
Revenues
Revenue from contract with customer	$ 251,741,000	$ 434,713,000	$ 402,485,000
Oil and Condensate [Member]
Revenues
Revenue from contract with customer	8,948,000	16,589,000	21,073,000
Natural Gas, Production [Member]
Revenues
Revenue from contract with customer	10,103,000	17,733,000	15,972,000
Product and Service, Other [Member]
Revenues
Revenue from contract with customer	$ 2,458,000	$ 2,176,000	$ 1,479,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (310,557)	$ 70,589	$ 224,785
Other comprehensive income (loss):
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	(72)	(141)	82
Total other comprehensive income (loss), net of tax	(72)	(141)	82
Comprehensive income (loss)	$ (310,629)	$ 70,448	$ 224,867

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 13,020	$ 7,798
Accounts receivable, net of allowance for credit losses	42,562	70,716
Derivative assets	78,793	4,131
Income taxes receivable	0	1,236
Prepaid and other current assets	19,045	4,458
Total current assets	153,420	88,339
Property and equipment, net (full cost method)	723,549	1,120,425
Derivative assets	25,449	2,750
Other assets	4,908	6,724
Total assets	907,326	1,218,238
Current liabilities
Accounts payable and accrued liabilities	62,768	105,824
Derivative liabilities	85,427	23,450
Total current liabilities	148,195	129,274
Other liabilities	8,362	8,382
Deferred income taxes	0	1,424
Derivative liabilities	28,434	3,385
Long-term debt, net	509,497	555,028
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; 15,200,435 and 15,135,598 shares issued as of December 31, 2020 and 2019, respectively	152	151
Paid-in capital	203,463	200,666
Retained earnings	9,354	319,987
Accumulated other comprehensive loss	(131)	(59)
Total shareholders’ equity	212,838	520,745
Total liabilities and shareholders’ equity	$ 907,326	$ 1,218,238

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (310,557,000)	$ 70,589,000	$ 224,785,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash reorganization items	0	0	(3,322,000)
Depreciation, depletion and amortization	140,673,000	174,569,000	127,961,000
Asset Impairment Charges	391,849,000	0	0
Derivative contracts:
Net (gains) losses	(88,422,000)	68,131,000	(37,427,000)
Cash Settlements Derivatives, Operating Activities	(78,087,000)	4,136,000	48,291,000
Deferred income tax expense (benefit)	(1,424,000)	3,373,000	2,994,000
Loss (gain) on sales of assets, net	(18,000)	(5,000)	177,000
Noncash Interest Expense	4,150,000	3,354,000	3,416,000
Share-based compensation	3,284,000	4,082,000	4,618,000
Other, net	31,000	52,000	44,000
Changes in operating assets and liabilities:
Accounts receivable, net	28,078,000	(5,079,000)	(23,674,000)
Accounts payable and accrued expenses	(24,731,000)	4,690,000	21,109,000
Other assets and liabilities	778,000	574,000	(258,000)
Net cash provided by operating activities	221,778,000	320,194,000	272,132,000
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net	0	(6,516,000)	(85,387,000)
Capital expenditures	(168,565,000)	(362,743,000)	(430,592,000)
Proceeds from sales of assets, net	87,000	215,000	7,683,000
Net cash used in investing activities	(168,478,000)	(369,044,000)	(508,296,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from credit facility borrowings	51,000,000	76,400,000	244,000,000
Repayment of credit facility borrowings	(99,000,000)	(35,000,000)	0
Debt issuance costs paid	(78,000)	(2,616,000)	(989,000)
Net cash provided by (used in) financing activities	(48,078,000)	38,784,000	243,011,000
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	5,222,000	(10,066,000)	6,847,000
Cash and cash equivalents - beginning of period	7,798,000	17,864,000	11,017,000
Cash and cash equivalents - end of period	13,020,000	7,798,000	17,864,000
Cash paid for:
Interest, net of amounts capitalized	27,333,000	32,398,000	22,599,000
Income taxes, net of (refunds)	(2,471,000)	(2,471,000)	0
Reorganization items, net	0	79,000	540,000
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Increase (Decrease) in Accounts Receivable, Acquisitions	0	(152,000)	(27,107,000)
Increase (Decrease) in Other Assets, Acquisitions	0	0	(743,000)
Increase (Decrease) in Accrued Liabilities, Acquisitions	0	(540,000)	(11,182,000)
Capital Expenditures, Period Increase (Decrease)	(18,671,000)	(3,602,000)	44,000
Increase (Decrease) in ARO, Acquisitions	$ 0	$ 83,000	$ 385,000

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Accounting Standards Update 2016-02	Accounting Standards Update 2016-13	Accounting Standards Update 2014-09	Common Stock	Preferred Stock	Paid-in Capital	Retained Earnings	Retained EarningsAccounting Standards Update 2016-02	Retained EarningsAccounting Standards Update 2016-13	Retained EarningsAccounting Standards Update 2014-09	Accumulated Other Comprehensive Income (Loss)
Balance as of beginning of period (in shares) at Dec. 31, 2017					15,019
Balance as of beginning of period at Dec. 31, 2017	$ 221,639			$ (2,659)	$ 150	$ 0	$ 194,123	$ 27,366			$ (2,659)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	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)						0	0				(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	$ (94)			$ 151	0	197,630	249,492	$ (94)			82
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	70,589							70,589
Share-based compensation							4,082
Restricted stock unit vesting (in shares)					56
Restricted stock unit vesting	(1,046)				$ 0		(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		$ (76)		$ 151	0	200,666	319,987		$ (76)		(59)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(310,557)							(310,557)
Share-based compensation							3,284
Restricted stock unit vesting (in shares)					64
Restricted stock unit vesting	(486)				$ 1		(487)
Other	72											72
Balance as of end of period (in shares) at Dec. 31, 2020					15,200
Balance as of end of period at Dec. 31, 2020	$ 212,838				$ 152	$ 0	$ 203,463	$ 9,354				$ (131)

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Preferred Stock, Shares Authorized	5,000,000
Preferred Stock, Shares Issued	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	45,000,000	45,000,000
Common Stock, Shares, Issued	15,200,435	15,135,598
Series A Preferred Stock
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	5,000,000	5,000,000
Preferred Stock, Shares Issued	0	0

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2020
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 focused on 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, 2020
Accounting Policies [Abstract]
Basis of Presentation	2. Basis of Presentation Adoption of Recently Issued Accounting Pronouncements and Comparability to Prior Periods Effective January 1, 2020, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”). We adopted ASU 2016–13 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2020 (see Note 5 for the impact and disclosures associated with the adoption of ASU 2016–13). Effective January 1, 2019, we adopted and began applying the relevant guidance provided in 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 of $0.1 million to the beginning balance of retained earnings as of January 1, 2019. 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 and 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. Comparative periods and related disclosures have not been restated for the application of ASU 2016–13 and ASC Topic 842. Accordingly, certain components of our Consolidated Financial Statements are not comparable between periods and the Consolidated Statement of Operations for the years ended December 31, 2019 and 2018 are presented based on prior GAAP for credit losses and leases, respectively, in their entirety. Subsequent Events At a special meeting held on January 13, 2021, the Company’s shareholders approved the potential issuance of up to 22,597,757 shares of our common stock, par value $0.01 per share (the “Common Stock”), upon the redemption or exchange of up to 225,977.57 shares of Series A Preferred Stock, par value $0.01 per share, of the Company (“Series A Preferred Stock”), together with up to 22,597,757 common units representing limited partner interests (the “Common Units”) of PV Energy Holdings, L.P. (the “Partnership”). On January 14, 2021, the Company amended its articles of incorporation (the “Articles of Amendment”) creating a series of the Company’s preferred stock consisting of 300,000 shares and designated as the Series A Preferred Stock, as well as establishing the powers, preferences and rights of the preferred stock series and the qualifications, limitations and restrictions thereof. On January 15, 2021, or the Closing Date, the Company consummated the previously announced transactions, (collectively, the “Juniper Transactions”), contemplated by: (i) the Contribution Agreement, dated November 2, 2020 (the “Contribution Agreement”), by and among the Company, the Partnership, and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital”), and, together with its affiliates (“Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Asset Agreement,” and, together with the Contribution Agreement, the “Juniper Transaction Agreements”), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership. In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure (the “Reorganization”) (which is intended to, among other things, result in the holders of the Series A Preferred Stock, having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership), including (i) the conversion of each of the Company’s corporate subsidiaries into limited liability companies which are disregarded for U.S. federal income tax purposes, including the conversion of Penn Virginia Holding Corp. into Penn Virginia Holdings, LLC, a Delaware limited liability company (“Holdings”), and (ii) the Company’s contribution of all of its equity interests in Holdings to the Partnership in exchange for 15,268,686 newly issued Common Units. On the Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, as a capital contribution, $150 million in cash in exchange for 17,142,857 newly issued Common Units and the Company issued to JSTX 171,428.57 shares of Series A Preferred Stock at a price equal to the par value of the shares acquired, and (ii) pursuant to the terms of the Asset Agreement, Rocky Creek contributed to our operating subsidiary certain oil and gas assets in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in an indemnity escrow to support post-closing indemnification claims, 50% of such escrowed amount to be disbursed 180 days after the Closing and the remainder one year after the Closing. Concurrent with the closing of the Juniper Transaction, on the Closing Date, the following transactions occurred: (i) the Agreement and Amendment No. 9 to Credit Agreement (the “Ninth Amendment”) to the credit agreement (the “Credit Facility”) became effective and a prepayment of $80.5 million of outstanding borrowings under the Credit Facility was made plus accrued interest of $0.1 million, (ii) the amendment dated November 2, 2020 (the “Second Lien Amendment”) to the Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) became effective and a prepayment of $50.0 million of outstanding advances under the Second Lien Facility was made plus accrued interest of $0.2 million in accordance with the Second Lien Amendment, (iii) total payments of $17.8 million in cash were completed for transaction and debt issue costs, including (A) $16.0 million associated with the Juniper Transactions, (B) $1.4 million associated with the Second Lien Amendment and (C) $0.4 million associated with the Ninth Amendment and (iv) a combined payment of $1.3 million including principal and accrued interest was made to liquidate the outstanding advances attributable to a single participant lender. We incurred a total of $18.5 million for certain professional fees, including advisory, legal, consulting fees and other costs in connection with the Juniper Transactions. A total of $5.0 million were attributable to services and costs incurred in 2020. The remaining $13.5 million includes $5.5 million of costs incurred by Juniper that were to be paid by the Company as a condition of closing the Juniper Transaction Agreements as well as $8.0 million of other fees and costs that were incurred in January 2021 or otherwise incurred contingent upon the closing. All of the costs incurred in 2020 have been recognized in general and administrative expenses (“G&A”). Of the costs incurred in January 2021 and those associated with the closing, $4.2 million will be recognized as a component of G&A and $9.3 million, including the aforementioned $5.5 million of costs incurred by Juniper and $3.8 million of costs incurred by us related to the issuance of the Series A Preferred Stock and Common Units, will be classified as a reduction to the capital contribution on our Consolidated Balance Sheet. Following the Juniper Transactions, Edward Geiser, Juniper’s Managing Partner, began serving as Penn Virginia’s Chairman of the Board, and Juniper appointed four additional members to the Board. Darrin Henke and the other members of our senior management are continuing in their roles, and the Company’s current directors, including Mr. Henke, have remained on the Board following the closing. Management has evaluated all of our activities through the issuance date of our Consolidated Financial Statements and has concluded that, other than the aforementioned Juniper Transactions, the Ninth Amendment (see Note 9), the Second Lien Amendment (see Note 9), no subsequent events have occurred that would require recognition in our Consolidated Financial Statements or disclosure in the Notes thereto. Risks and Uncertainties As an oil and gas exploration and development company, we are exposed to a number of risks and uncertainties that are inherent to our industry. The global public health crisis associated with the novel coronavirus (“COVID-19”) has, and is anticipated to continue to have, an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures, limitations to person-to-person contact and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy in 2020, which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse that began in early March 2020 as a direct result of disagreements between the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) with respect to production curtailments. OPEC+ ultimately agreed to specified adjustments to production in the Spring of 2020 which, for the most part, held for the remainder of the year and were supplemented by additional voluntary downward adjustments, led primarily by Saudi Arabia. Collectively these curtailments have contributed to a relative stabilization of commodity prices and rebalancing of the global crude oil markets by the end of 2020. Notwithstanding the relative improvement in global market stability, as a result of several factors including rising infection rates at the beginning of 2021, mutating strains of the virus, the return of stricter lockdown measures and logistical challenges in vaccine distribution, among others, a return to pre-COVID 19 levels of economic activity remain uncertain in their magnitude and eventual timing. Nonetheless, OPEC+ indicated in their January 2021 meeting a commitment to gradually return limited production to the market with the pace being determined by market conditions. An additional meeting is scheduled for early March of 2021 to monitor conditions and progress. A significant decline in domestic drilling by U.S. producers began in mid-March 2020 and continued through most of the second half of the year. The overall economic decline had an adverse impact on the entire industry, but particularly on smaller upstream producers with limited financial resources as well as oilfield service companies. While a modest recovery in activity began in the fourth quarter of 2020, including a resumption of our own drilling program, domestic supply and demand imbalances continue to stress the market which is further exacerbated by capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region. While there exists encouraging signs for continued recovery due to the aforementioned vaccine development as well as a commitment by the new U.S. Administration to prioritize economic relief efforts, the relative success of such efforts is difficult to predict with respect to timing and the resulting economic impact. Accordingly, the combined effect of the global and domestic factors discussed herein is anticipated to continue to contribute to overall volatility within the industry generally and to our operations specifically. During 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position and liquidity. The more significant actions that we took during that time included: (i) temporarily suspending our drilling program from April through September 2020, (ii) curtailing production through selected well shut-ins for a period of several weeks in April and May, (iii) securing additional crude oil storage capacity (see Note 14) in order to maintain a reasonable level of production to (a) allow for the continued marketing of NGLs and natural gas rather than delaying revenues through additional shut-ins and (b) capitalize on potential increases in commodity prices, (iv) substantially expanding the scope and range of our commodity derivatives portfolio (see Note 6), (v) utilizing certain provisions of the Coronavirus Aid, Relief and Economic Security Act (the “CARES Act”) and related regulations, the most significant of which resulted in the receipt in June 2020 of an accelerated refund of our remaining refundable alternative minimum tax (“AMT”) credit carryforwards in the amount of $2.5 million and (vi) elimination of annual cost-of-living and similar adjustments to our salaries and wages for 2020, and in July 2020, a limited reduction-in-force (“RIF”). We incurred and paid employee termination and severance benefits of approximately $0.2 million in connection with the limited RIF and those costs have been included in G&A.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
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 We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. 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. We have elected to report all of our derivative asset and liability positions on a gross basis on our Consolidated Balance Sheet and not net the positions, even when a legal right-of-setoff exists. Our derivative instruments are not formally designated as hedges in the context of GAAP. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. We recognize changes in fair value in earnings currently as a component of the Derivatives caption in our Consolidated Statements of Operations. 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 after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices 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, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – fifteen three 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. 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 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 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 do 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 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 it may be incurred, 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 Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient 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. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities. 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. 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 gathering, processing and transportation expense (“GPT”). 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 regarding 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. Natural gas . Subsequent to the 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 and water disposal services . We provide marketing and water disposal 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 fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in G&A expenses and direct costs associated with our water service efforts are netted against the underlying revenue. Credit Losses We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10 percent in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10 percent in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable. 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 forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A in our Consolidated Statements of Operations. Reorganization Items Includes adjustments directly attributable to the final administration and discharge of our bankruptcy case in connection with a final decree that was issued in November 2018 and that are not a part of our continuing operations.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2020
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 Valuation of Acquisition The fair values of the oil and gas properties acquired in the Hunt Acquisition 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 Acquisition on Actual and Pro Forma Results of Operations The results of operations attributable to the Hunt Acquisition have been included in our Consolidated Financial Statements for the periods after March 1, 2018. 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 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 year ended December, 31, 2018 assuming the Hunt Acquisition 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 Acquisitions had occurred as of this date, or the results of operations for any future periods. Total revenues $ 446,077 Net income $ 227,930 Net income per share - basic $ 15.14 Net income per share - diluted $ 14.91 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 for the year ended December 31, 2018. 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, 2020
Receivables [Abstract]
Accounts Receivable and Major Customers	Accounts Receivable and Revenues from Contracts with Customers The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2020 2019 Customers $ 39,672 $ 63,165 Joint interest partners 3,079 6,929 Other 8 674 42,759 70,768 Less: Allowance for credit losses (197) (52) $ 42,562 $ 70,716 Revenue from Contracts with Customers For the year ended December 31, 2020, three customers accounted for $150.8 million, or approximately 56% of our consolidated product revenues. The revenues generated from these customers during 2020 were $72.3 million, $50.2 million, and $28.3 million or 27%, 19%, and 10% of the consolidated total, respectively. As of December 31, 2020, $18.6 million, or approximately 47% of our consolidated accounts receivable from customers was related to these customers. 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 approximately 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. Credit Losses and Allowance for Credit Losses Adoption of ASU 2016–13 Effective January 1, 2020, we adopted ASU 2016–13 and have applied the guidance therein to our portfolio of accounts receivable including those from our customers and our joint interest partners. We have adopted ASU 2016–13 using the modified retrospective method resulting in an adjustment of less than $0.1 million to the beginning balance of retained earnings and a corresponding increase to the allowance for credit losses as of January 1, 2020. As of December 31, 2020, the allowance for credit losses is entirely attributable to certain receivables from joint interest partners as described below. Customers . We sell our commodity products to approximately 20 customers. A substantial majority of these customers are large, internationally recognized refiners and marketers in the case of our crude oil sales and large domestic processors and interstate pipelines with respect to our NGL and natural gas sales. As noted in our disclosures regarding major customers above, a significant portion of our outstanding customer accounts receivable are concentrated within a group of up to five customers at any given time. Due primarily to the historical market efficiencies and generally timely settlements associated with commodity sale transactions for crude oil, NGLs and natural gas, we have assessed this portfolio segment at zero risk for credit loss upon the adoption of ASU 2016–13 and for each of the periods included in the year ended December 31, 2020. Historically, we have never experienced a credit loss with such customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. Mutual Operators . As of December 31, 2020, we had mutual joint interest partner relationships with two upstream producers that also operate properties within the Eagle Ford for which we have non-operated working interests. Historically we have had full and timely collection experiences with these entities and we ourselves are timely with respect to our payments to them of joint venture costs. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at zero risk for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have assessed receivables originating in 2020 with a 5 percent risk. Large Partners . As of December 31, 2020, three legal entities had working interests of 10 percent or greater in properties that we operate. These entities are primarily passive investors. Historically we have had full and timely collection experiences with these entities. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at a risk of 1 percent for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have increased the assessed receivables originating in 2020 to a 2 percent risk. All Others . As of December 31, 2020, approximately 20 legal entities had working interests of less than 10 percent in properties that we operate. Historically, this is the only portfolio segment with whom we have experienced credit losses. Generally, this group includes passive investors and smaller producers that may not have the wherewithal or alternative sources of liquidity to settle their obligations to us in the event of individual challenges unique to smaller entities as well as adverse economic conditions in general. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at a risk of 5 percent for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have increased the assessed receivables originated in 2020 to a 10 percent risk. As of December 31, 2020, approximately $0.2 million of accounts receivables attributable to this portfolio segment was past due, or over 60 days. The following table summarizes the activity in our allowance for credit losses, by portfolio segment, for the year ended December 31, 2020: Joint Interest Partners Customers Mutual Operators Large Partners All Others Total Balance at beginning of period $ — $ — $ — $ 52 $ 52 Adjustment upon adoption — — 60 16 76 Provision for expected credit losses — 9 27 33 69 Write-offs and recoveries — — — — — Balance at end of period $ — $ 9 $ 87 $ 101 $ 197

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We utilize derivative instruments, typically swaps, put options and call options 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 the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. Commodity Derivatives The following is a general description of the commodity derivative instruments we have employed: Swaps . A swap contract is an agreement between two parties pursuant to which the parties exchange payments at specified dates on the basis of a specified notional amount, or the swap price, with the payments calculated by reference to specified commodities or indexes. The purchasing counterparty to a swap contract is required to make a payment to selling counterparty based on the amount of the swap price in excess of the settlement price multiplied by the notional volume 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 based on the amount of the settlement price in excess of the swap price multiplied by the notional volume if the settlement price for any settlement period is above the swap price for such contract. Put Options . A put option has a defined strike, or floor price. We have entered into put option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the put option pays the seller a premium to enter into the contract. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is above the floor price, the put option expires worthless. Certain of our purchased put options have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of settlement. Call Options. A call option has a defined strike, or ceiling price. We have entered into call option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is below the ceiling price, the call option expires worthless. We typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others. We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions, including current market value and contractual prices for the underlying instruments, implied volatilities, time value and nonperformance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX West Texas Intermediate (“NYMEX WTI”), Magellan East Houston (“MEH”) crude oil and NYMEX Henry Hub (“NYMEX HH”) natural gas closing prices as of the end of the reporting period. Nonperformance risk is incorporated by utilizing 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. The following table sets forth our commodity derivative contracts as of December 31, 2020: 1Q2021 2Q2021 3Q2021 4Q2021 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 NYMEX WTI Crude Swaps Average Volume Per Day (barrels) 3,889 3,297 815 815 Weighted Average Swap Price ($/barrel) $ 54.38 $ 55.89 $ 45.54 45.54 NYMEX WTI Crude Collars Average Volume Per Day (barrels) 9,722 10,440 9,239 8,152 2,917 2,885 2,853 2,853 2,917 2,855 Weighted Average Purchased Put Price ($/barrel) $ 40.00 $ 42.84 $ 40.35 $ 40.40 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 Weighted Average Sold Call ($/barrel) $ 45.78 $ 51.70 $ 51.85 $ 52.10 $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ 50.00 NYMEX WTI Purchased Puts Average Volume Per Day (barrels) 1,667 Weighted Average Purchased Put Price ($/barrel) $ 55.00 NYMEX WTI Sold Puts Average Volume Per Day (barrels) 556 11,538 5,707 5,707 Weighted Average Sold Put ($/barrel) $ 26.50 $ 36.93 $ 35.14 35.14 MEH-NYMEX WTI Crude Basis Swaps Average Volume Per Day (barrels) 8,889 Weighted Average Swap Price ($/barrel) $ 1.16 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (barrels) 14,444 13,187 13,043 13,043 Weighted Average Swap Price ($/barrel) $ (0.18) $ 0.07 $ 0.07 $ 0.07 NYMEX HH Collars Average Volume Per Day (MMBtus) 10,000 9,890 9,783 9,783 Weighted Average Purchased Put Price ($/MMBtu) $ 2.607 $ 2.607 $ 2.607 $ 2.607 Weighted Average Sold Call ($/MMBtu) $ 3.117 $ 3.117 $ 3.117 $ 3.117 NYMEX HH Sold Puts Average Volume Per Day (MMBtus) 6,667 6,593 6,522 6,522 Weighted Average Sold Put Strike ($/MMBtu) $ 2.000 $ 2.000 $ 2.000 $ 2.000 As of December 31, 2020, we were unhedged with respect to NGL production. Interest Rate Derivatives We have entered into a series of interest rate swap contracts (the “Interest Rate Swaps”) to establish fixed interest rates on a portion of our variable interest rate indebtedness under the Credit Facility and the Second Lien Facility. The notional amount of the Interest Rate Swaps totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022. 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 and premiums received (paid), net.” The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2020 2019 2018 Interest rate swap losses recognized in the Consolidated Statements of Operations $ (7,510) $ — $ — Commodity gains (losses) recognized in the Consolidated Statements of Operations 95,932 (68,131) 37,427 $ 88,422 $ (68,131) $ 37,427 Interest rate cash settlements recognized in the Consolidated Statements of Cash Flows $ (2,210) $ — $ — Commodity cash settlements and premiums received (paid) recognized in the Consolidated Statements of Cash Flows 80,297 (4,136) (48,291) $ 78,087 $ (4,136) $ (48,291) 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, 2020 December 31, 2019 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Interest rate contracts Derivative assets/liabilities – current $ — $ 3,655 $ — $ — Commodity contracts Derivative assets/liabilities – current 78,793 81,772 4,131 23,450 Interest rate contracts Derivative assets/liabilities – noncurrent — 1,645 — — Commodity contracts Derivative assets/liabilities – noncurrent 25,449 26,789 2,750 3,385 $ 104,242 $ 113,861 $ 6,881 $ 26,835 As of December 31, 2020, we reported net commodity derivative liabilities of $4.3 million and net Interest Rate Swap liabilities of $5.3 million. The contracts associated with these position are with eight counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in the Credit Facility. This concentration may impact our overall credit risk 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, 2020
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, 2020 2019 Oil and gas properties: Proved $ 1,545,910 $ 1,409,219 Unproved 49,935 53,200 Total oil and gas properties 1,595,845 1,462,419 Other property and equipment 27,746 25,915 Total property and equipment 1,623,591 1,488,334 Accumulated depreciation, depletion and amortization (900,042) (367,909) $ 723,549 $ 1,120,425 Unproved property costs of $49.9 million and $53.2 million have been excluded from amortization as of December 31, 2020 and December 31, 2019, respectively. An additional $1.2 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, 2020. The total costs not subject to amortization as of December 31, 2020 were incurred in the following periods: $2.2 million in 2020, $1.6 million in 2019, $2.0 million in 2018 and $44.2 million prior to 2018 as well as $1.1 million of capitalized interest applied thereto. We transferred $8.3 million and $16.8 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, 2020 and 2019, respectively. We capitalized internal costs of $2.1 million, $4.1 million and $3.7 million and interest of $2.7 million, $4.1 million and $9.1 million during the year ended December 31, 2020, 2019 and 2018 respectively, in accordance with our accounting policies. Average DD&A per BOE of proved oil and gas properties was $15.83, $17.25 and $16.11 for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, the carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test by $120.3 million. Accordingly, we recorded an impairment of our oil and gas properties by this amount for the three months ended December 31, 2020, and when combined with the $271.5 million record in the first nine months of 2020, $391.8 million for the year ended December 31, 2020. Because the Ceiling Test utilizes commodity prices based on a trailing twelve month average, as of December 31, 2020 it does not fully reflect the substantial decline in commodity prices that accelerated early in the second quarter of 2020 due to the economic impact of the COVID-19 pandemic and the ongoing disruption in global energy markets. Accordingly, we may incur an additional impairment during the first quarter of 2021.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement ObligationsThe 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, 2020 2019 Balance at beginning of period $ 4,934 $ 4,314 Changes in estimates 33 (2) Liabilities incurred 121 290 Liabilities settled — (67) Acquisitions of properties 16 83 Accretion expense 357 316 Balance at end of period $ 5,461 $ 4,934

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The following table summarizes our long-term debt as of the dates presented: December 31, 2020 December 31, 2019 Principal Unamortized Discount and Issuance Costs 1, 2 Principal Unamortized Discount and Issuance Costs 1, 2 Credit facility $ 314,400 $ 362,400 Second lien term loan 200,000 $ 4,903 200,000 $ 7,372 Totals 514,400 4,903 562,400 7,372 Less: Unamortized discount (“OID”) 2 (1,604) (2,415) Less: Unamortized deferred issuance costs 1, 2 (3,299) (4,957) Long-term debt, net $ 509,497 $ 555,028 _____________________________________________ 1 Excludes 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. 2 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method. Credit Facility The Credit Facility provides for a $1.0 billion revolving commitment and a $375 million borrowing base including a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base; however, outstanding borrowings under the Credit Facility are limited to a maximum of $350 million until the next redetermination of the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. Certain minimum hedging and other conditions included in the Ninth Amendment were initially satisfied in February 2021 which allow for a borrowing base holiday until Fall 2021 assuming we continue to satisfy the conditions. The Credit Facility is available to us for general corporate purposes, including working capital. The Credit Facility is scheduled to mature in May 2024. We had $0.4 million in letters of credit outstanding as of December 31, 2020 and 2019. In the years ended December 31, 2020 and 2019, we incurred and capitalized issue costs of $0.1 million and $2.6 million, respectively, in connection with amendments to the Credit Facility and wrote off $0.9 million of previously capitalized issue costs due to a decrease in the borrowing base associated with an amendment during the first half of 2020. We incurred and capitalized $0.4 million of issue costs in January 2021 in connection with the Ninth Amendment. In addition to the requirement to repay outstanding borrowings of $80.5 million under the Credit Facility from the proceeds of the Juniper Transactions, the Ninth Amendment provides for: (i) the aforementioned borrowing base holiday, (ii) introduces a first lien leverage ratio covenant of 2.50 times, tested quarterly and (iii) permits amortization payments of up to $1.875 million per quarter to be made under the Second Lien Facility until January 2022 if no default exists both before and after giving effect to the payments and thereafter using available free cash flow upon the satisfaction of certain conditions (including maintaining a leverage ratio of 2.00 to 1.00 and availability of at least 25% under the Credit Facility after giving pro forma effect to the payment). In addition, the Ninth Amendment provides for a minimum hedge condition that further limits the type of instruments to be utilized, the notional volume to be hedged and sets a minimum floor price for certain contracts as well as a provision for the replacement of the LIBOR interest rate upon its expiration in 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 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including LIBOR through 2021, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level 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 Eurodollar borrowings is payable every one three The Credit Facility is guaranteed by the Partnership and all of its subsidiaries (excluding the borrower subsidiary)(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 the ability of the borrower 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 subsidiaries’ 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, (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 3.50 to 1.00 and (3) a maximum first lien leverage ratio (consolidated secured 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 2.50 to 1.00. The Credit Facility also contains 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, weekly cash balance reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. In addition, the Credit Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million. The Credit Facility contains events of default and remedies. 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, 2020, 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 and the proceeds were used to fund a significant acquisition and related fees and expenses. 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%. 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 term of the Second Lien Facility. On November 2, 2020, we entered into the Second Lien Amendment which became effective upon the closing of the Juniper Transactions. In addition to a required prepayment of $50.0 million of outstanding advances under the Second Lien Facility, the Second Lien Amendment provides for (i) the extension of the maturity date of the Second Lien Facility to September 29, 2024, (ii) an increase to the margin applicable to advances under the Second Lien Facility; (iii) the imposition of certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00, (iv) the requirement for maximum and, in certain circumstances as described therein, minimum hedging arrangements, (v) beginning in 2021, a requirement to make quarterly amortization payments equal to $1.875 million and (vi) a provision for the replacement of the LIBOR interest rate upon its expiration in 2022. On the Closing Date, we entered into the Omnibus Amendment to the Second Lien Facility (the “Omnibus Amendment”) to, among other things, effectuate the release of the Company from its guarantee of the obligations under the Second Lien Facility and its grant of a security interest in its assets. In January 2021, we incurred and capitalized $1.4 million of issue costs in connection with the Second Lien Amendment and wrote off $1.3 million of previously capitalized issue costs and OID allocable to the $50.0 million prepayment and a $1.3 million principal payment to liquidate the outstanding advances attributable to a single participant lender. The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin of 8.25% or (b) a Eurodollar rate, including LIBOR through 2021, with a floor of 1.00%, plus an applicable margin of 7.25%; provided that the applicable margin will increase to 9.25% and 8.25%, respectively, during any quarter in which the quarterly amortization payment is not made. As of December 31, 2020, the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.00%. 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 Eurodollar borrowings is payable every one or 3 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 Eurodollar loans): from January 15, 2021 through January 14, 2022, 102% of the amount being prepaid, from January 15, 2022 through January 14, 2023, 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 January 15, 2021 through January 14, 2022, 102% of the amount being prepaid, from January 15, 2023 through January 14, 2023, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility is collateralized by substantially all of the Partnership’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 the Partnership and the Subsidiary Guarantors. The Second Lien Facility has no financial covenants, but contains 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 capital expenditures, investments, the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends and transactions with affiliates and other customary covenants. As of December 31, 2020, 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, 2020 2019 2018 Current income taxes (benefit) Federal $ (1,236) $ (1,236) $ (2,471) State 357 — — (879) (1,236) (2,471) Deferred income taxes (benefit) Federal 1,236 1,236 2,471 State (2,660) 2,137 523 (1,424) 3,373 2,994 $ (2,303) $ 2,137 $ 523 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 expense (benefit) for the periods presented: Year Ended December 31, 2020 2019 2018 Computed at federal statutory rate $ (65,701) (21.0) % $ 15,272 21.0 % $ 47,315 21.0 % State income taxes, net of federal income tax benefit (1,856) (0.6) % 1,494 2.1 % 1,743 0.8 % Change in valuation allowance 64,062 20.5 % (14,240) (19.6) % (48,820) (21.7) % Other, net 1,192 0.4 % (389) (0.5) % 285 0.1 % $ (2,303) (0.7) % $ 2,137 3.0 % $ 523 0.2 % The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented: December 31, 2020 2019 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 180,531 $ 175,221 Alternative minimum tax (“AMT”) credit carryforwards — 1,236 Asset retirement obligations 1,188 1,073 Pension and postretirement benefits 301 340 Share-based compensation 467 880 Fair value of derivative instruments 2,737 4,191 Interest expense limitation — 11,463 ROU assets 564 — Other 1,484 2,441 187,272 196,845 Less: Valuation allowance (179,006) (114,939) Total net deferred tax assets 8,266 81,906 Deferred tax liabilities: Property and equipment 7,728 83,330 ROU obligations 538 — Total deferred tax liabilities 8,266 83,330 Net deferred tax liabilities $ — $ (1,424) Income Tax Provision The provision for the years ended December 31, 2020, 2019 and 2018 includes current federal benefits of $1.2 million, $1.2 million and $2.5 million attributable to refunds of AMT credits for the 2020, 2019 and 2018 tax years, respectively. The amounts attributable to 2020 combined the amounts attributable to 2019, which had been recognized on our Consolidated Balance Sheet as of December 31, 2019 as a current asset, were received in 2020 as an acceleration of all AMT credits in connection with certain provisions of the CARES Act. 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, 2020, 2019 and 2018, respectively. In addition, we have recognized deferred state tax benefits of $2.7 million and expenses of $2.1 million and $0.5 million attributable to property and equipment as well as $0.4 million of current state expense attributable to the Texas margin tax for the year ended December 31, 2020 for overall effective tax rates of 0.7%, 3.0% and 0.2% for the years ended December 31, 2020, 2019 and 2018, respectively. Deferred Tax Assets and Liabilities As of December 31, 2020, we had federal NOL carryforwards of approximately $638.6 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. Because of the change in ownership provisions of the Code, use of a portion of our federal NOLs may be limited in future periods. As of December 31, 2020, we carried a valuation allowance against our federal and state deferred tax assets of $179.0 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 valuation allowance along with $8.3 million of deferred tax liabilities fully offset our deferred tax assets. Accordingly, there are no net deferred tax assets or liabilities reflected on our Consolidated Balance Sheet as of December 31, 2020. 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. Other Income Tax Matters We had no liability for unrecognized tax benefits as of December 31, 2020 and 2019. There were no interest and penalty charges recognized during the years ended December 31, 2020, 2019 and 2018. 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 We generally have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, crude oil storage tank capacity, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases included in the disclosures below are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs, crude oil storage tank capacity and our field compressors. Our primary variable lease was represented by 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 periods presented: Year Ended December 31, 2020 2019 Operating lease cost $ 979 $ 773 Short-term lease cost 23,721 36,202 Variable lease cost 21,932 23,762 Less: Amounts charged as drilling costs 1 (20,708) (33,354) Total lease cost recognized in the Consolidated Statement of Operations 2 $ 25,924 $ 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 $11.2 million and $12.1 million recognized in GPT, $13.8 million and $14.5 million recognized in Lease operating expense (“LOE”) and $1.0 million and $0.8 million recognized in G&A for the years ended December 31, 2020 and 2019, respectively. Operating lease rental expense, as determined in accordance with prior GAAP was $2.7 million for the year ended December 31, 2018, 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 2020 and 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 periods presented: Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 943 $ 659 ROU assets obtained in exchange for operating lease obligations 1 $ 388 $ 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 the dates presented: December 31, 2020 2019 ROU assets – operating leases $ 2,432 $ 2,740 Current operating lease obligations $ 936 $ 847 Noncurrent operating lease obligations 1,752 2,232 Total operating lease obligations $ 2,688 $ 3,079 Weighted-average remaining lease term – operating leases 3.1 years 4.1 years Weighted-average discount rate – operating leases 3.24 % 5.97 % Maturities of operating lease obligations for the years ending December 31, 2021 $ 936 2022 874 2023 872 2024 146 Total undiscounted lease payments 2,828 Less: imputed interest (140) Total operating lease obligations $ 2,688

Supplemental Balance Sheet Deta

Supplemental Balance Sheet Detail	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Detail	Supplemental Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2020 2019 Prepaid and other current assets: Tubular inventory and well materials $ 3,856 $ 2,989 Prepaid expenses 1 15,189 1,469 $ 19,045 $ 4,458 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 2,349 $ 3,952 Right-of-use assets – operating leases 2,432 2,740 Other 127 32 $ 4,908 $ 6,724 Accounts payable and accrued liabilities: Trade accounts payable $ 7,055 $ 30,098 Drilling costs 16,088 18,832 Royalties 26,615 44,537 Production, ad valorem and other taxes 3,094 3,244 Compensation and benefits 4,222 5,272 Interest 504 730 Current operating lease obligations 936 847 Other 2 4,254 2,264 $ 62,768 $ 105,824 Other liabilities: Asset retirement obligations $ 5,461 $ 4,934 Noncurrent operating lease obligations 1,752 2,232 Defined benefit pension obligations 865 873 Postretirement health care benefit obligations 284 343 $ 8,362 $ 8,382 _______________________ 1 The balance as of December 31, 2020 includes $13.6 million for the prepayment of drilling and completion services and materials in advance of the program for the first quarter of 2021. 2 The balance as of December 31, 2020 includes $3.5 million of accrued costs attributable to Juniper Transaction expenses.
Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2020 2019 Prepaid and other current assets: Tubular inventory and well materials $ 3,856 $ 2,989 Prepaid expenses 1 15,189 1,469 $ 19,045 $ 4,458 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 2,349 $ 3,952 Right-of-use assets – operating leases 2,432 2,740 Other 127 32 $ 4,908 $ 6,724 Accounts payable and accrued liabilities: Trade accounts payable $ 7,055 $ 30,098 Drilling costs 16,088 18,832 Royalties 26,615 44,537 Production, ad valorem and other taxes 3,094 3,244 Compensation and benefits 4,222 5,272 Interest 504 730 Current operating lease obligations 936 847 Other 2 4,254 2,264 $ 62,768 $ 105,824 Other liabilities: Asset retirement obligations $ 5,461 $ 4,934 Noncurrent operating lease obligations 1,752 2,232 Defined benefit pension obligations 865 873 Postretirement health care benefit obligations 284 343 $ 8,362 $ 8,382

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	13. Fair Value Measurements We apply the authoritative accounting provisions included in GAAP 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 variable-rate Credit Facility and Second Lien Facility borrowings. As of December 31, 2020, the carrying value of all these financial instruments approximated fair value. Our derivatives are marked-to-market and presented at their fair values. 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, 2020 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 78,793 $ — $ 78,793 $ — Commodity derivative assets – noncurrent $ 25,449 $ — $ 25,449 $ — Liabilities: Interest rate swap liabilities - current $ (3,655) $ — $ (3,655) $ — Interest rate swap liabilities - noncurrent $ (1,645) $ — $ (1,645) $ — Commodity derivative liabilities – current $ (81,772) $ — $ (81,772) $ — Commodity derivative liabilities – noncurrent $ (26,789) $ — $ (26,789) $ — 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) — 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, 2020, 2019 and 2018. 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 using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH natural gas closing prices as of the end of the reporting periods. Each of these is a level 2 input. • Interest rate swaps : We determine the fair values of our interest rate swaps using an income valuation approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. 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 Acquisition, 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, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The following table sets forth our significant commitments as of December 31, 2020, by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Other Commitments 2021 $ 12,962 $ 317 2022 12,962 184 2023 12,962 — 2024 12,962 — 2025 12,962 — Thereafter 24,827 — Total $ 89,637 $ 501 Drilling and Completion Commitments As of December 31, 2020, we had contractual commitments on a pad-to-pad basis for two drilling rigs. Additionally, we have an agreement, effective January 2, 2021, which can be terminated with 30 days’ notice by either party, to utilize certain frac services and related materials, with no minimum commitment, through December 31, 2021. Gathering and Intermediate Transportation Commitments We have long-term agreements with Nuevo G&T and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”) to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in 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 (“MVC”) 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. Under each of the agreements with Nuevo, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period. Crude Oil Storage As a component of the crude oil gathering agreement referenced above, we have access up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. We have also contracted for access up to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis which can be terminated by either party with 45-days’ notice to the counterparty. We have also contracted for crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis which can be terminated by either party with 45-days’ notice to the counterparty. Finally, we have an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis through April 2021. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT. 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, 2020, we had an estimated reserve in the amount of $0.1 million for certain claims made against us regarding previously divested operations included in “Accounts payable and accrued liabilities.” Environmental Compliance

Shareholders' Equity

Shareholders' Equity	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Shareholders' Equity	Shareholders’ Equity Preferred Stock As of December 31, 2020 and December 31, 2019, there were 5,000,000 shares of preferred stock authorized with none issued or outstanding. Common Stock As of December 31, 2020 and December 31, 2019, there were 15,200,435 and 15,135,598 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)

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2020
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 (the “Incentive Plan”) for future share-based compensation awards. A total of 641,997 time-vested restricted stock units (“RSUs”) and 258,991 performance restricted stock units (“PRSUs”) have been granted as of December 31, 2020 including 57,500 RSUs and 57,500 PRSUs that were issued as an inducement award outside of the Incentive Plan. We recognized $3.3 million, $4.1 million and $4.6 million of share-based compensation expense for the years ended December 31, 2020, 2019 and 2018, 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 Weighted-Average Balance at beginning of year 136,876 $ 49.76 Granted 281,382 $ 4.49 Vested (63,916) $ 43.30 Forfeited (35,062) $ 27.83 Balance at end of year 319,280 $ 13.56 As of December 31, 2020, we had $3.0 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.0 years. The total grant-date fair values of RSUs that vested in 2020, 2019 and 2018 was $2.8 million, $3.0 million and $3.3 million, respectively. Performance Restricted Stock Units In the years ended December 31, 2020 and December 31, 2019, we granted 145,399 and 15,066 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 separate tranches with individual performance periods beginning in January 2019, 2020 and 2021, 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 and 2020, 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 $34.02 per PRSU for the 2019 grant and a range of $2.40 to $16.02 for the 2020 grants. The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2020, 2019 and 2017 are presented as follows: 2020 2019 Expected volatility 101.32% to 117.71% 49.9 % Dividend yield 0.0% 0.0% Risk-free interest rate 0.18% to 0.51% 1.66 % The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Weighted-Average Grant Date Balance at beginning of year 79,914 $ 52.73 Granted 145,399 $ 7.79 Vested (31,146) $ 58.35 Forfeited (20,635) $ 55.99 Balance at end of year 173,532 $ 13.68 As of December 31, 2020, we had $1.5 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.3 years. Executive Transition and Retirement In August 2020, we appointed Darrin Henke our new president and chief executive officer, or CEO, and director following the retirement of John Brooks. We incurred incremental G&A costs of approximately $1.2 million, in connection with Mr. Henke’s appointment and Mr. Brooks’ separation. In addition to those incremental costs, we recognized $0.7 million during the year ended December 31, 2020 for the accelerated vesting of certain share-based compensation awards of Mr. Brooks in connection with his retirement. In December 2019, 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, $0.9 million, $0.6 million for the years ended December 31, 2020, 2019 and 2018, 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 $0.2 million and $0.3 million are included in the “Accounts payable and accrued expenses” caption on our Consolidated Balance Sheets as of December 31, 2020 and 2019, 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, 2020, 2019 and 2018, and is included as a component of “Other, net” in our Statements of Operations. The combined unfunded benefit obligations under these plans were $1.3 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, 2020 and 2019.

Interest Expense

Interest Expense	12 Months Ended
	Dec. 31, 2020
Interest Expense [Abstract]
Interest Expense	Interest Expense The following table summarizes the components of interest expense for the periods presented: Year Ended December 31, 2020 2019 2018 Interest on borrowings and related fees $ 29,851 $ 36,593 $ 32,164 Accretion of original issue discount 1 811 743 680 Amortization of debt issuance costs 2 3,339 2,611 2,736 Capitalized interest (2,744) (4,136) (9,118) $ 31,257 $ 35,811 $ 26,462 _____________________________________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 9).

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Net income (loss) – basic and diluted $ (310,557) $ 70,589 $ 224,785 Weighted-average shares – basic 15,176 15,110 15,059 Effect of dilutive securities 1 — 16 233 Weighted-average shares – diluted 15,176 15,126 15,292 _____________________________________________

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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, 2020, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”). We adopted ASU 2016–13 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2020 (see Note 5 for the impact and disclosures associated with the adoption of ASU 2016–13). Effective January 1, 2019, we adopted and began applying the relevant guidance provided in 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 of $0.1 million to the beginning balance of retained earnings as of January 1, 2019. 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 and 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. Comparative periods and related disclosures have not been restated for the application of ASU 2016–13 and ASC Topic 842. Accordingly, certain components of our Consolidated Financial Statements are not comparable between periods and the Consolidated Statement of Operations for the years ended December 31, 2019 and 2018 are presented based on prior GAAP for credit losses and leases, respectively, in their entirety.
Principles of Consolidation	Principles of Consolidation
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
Derivative Instruments	Derivative Instruments We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. 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 after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices 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, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. fifteen three
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. 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 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 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 do 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 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 it may be incurred, 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 Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient 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. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities. 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. 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 gathering, processing and transportation expense (“GPT”). 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 regarding 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. Natural gas . Subsequent to the 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 and water disposal services . We provide marketing and water disposal 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 fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in G&A expenses and direct costs associated with our water service efforts are netted against the underlying revenue.
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 forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A in our Consolidated Statements of Operations.
Revenue from Contract with Customer
Fair Value of Measurements	We apply the authoritative accounting provisions included in GAAP 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).
Financing Receivable, Allowance for Credit Losses, Policy for Uncollectible Amounts	Credit Losses We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10 percent in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10 percent in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable.
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 using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH natural gas closing prices as of the end of the reporting periods. Each of these is a level 2 input. • Interest rate swaps : We determine the fair values of our interest rate swaps using an income valuation approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2020
Acquisitions and Divestitures [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	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 year ended December, 31, 2018 assuming the Hunt Acquisition 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 Acquisitions had occurred as of this date, or the results of operations for any future periods. Total revenues $ 446,077 Net income $ 227,930 Net income per share - basic $ 15.14 Net income per share - diluted $ 14.91

Accounts Receivable and Major_2

Accounts Receivable and Major Customers (Tables)	12 Months Ended
	Dec. 31, 2020
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2020 2019 Customers $ 39,672 $ 63,165 Joint interest partners 3,079 6,929 Other 8 674 42,759 70,768 Less: Allowance for credit losses (197) (52) $ 42,562 $ 70,716
Revenue from External Customers by Products and Services [Table Text Block]
Financing Receivable, Allowance for Credit Loss	The following table summarizes the activity in our allowance for credit losses, by portfolio segment, for the year ended December 31, 2020: Joint Interest Partners Customers Mutual Operators Large Partners All Others Total Balance at beginning of period $ — $ — $ — $ 52 $ 52 Adjustment upon adoption — — 60 16 76 Provision for expected credit losses — 9 27 33 69 Write-offs and recoveries — — — — — Balance at end of period $ — $ 9 $ 87 $ 101 $ 197

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Positions	The following table sets forth our commodity derivative contracts as of December 31, 2020: 1Q2021 2Q2021 3Q2021 4Q2021 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 NYMEX WTI Crude Swaps Average Volume Per Day (barrels) 3,889 3,297 815 815 Weighted Average Swap Price ($/barrel) $ 54.38 $ 55.89 $ 45.54 45.54 NYMEX WTI Crude Collars Average Volume Per Day (barrels) 9,722 10,440 9,239 8,152 2,917 2,885 2,853 2,853 2,917 2,855 Weighted Average Purchased Put Price ($/barrel) $ 40.00 $ 42.84 $ 40.35 $ 40.40 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 Weighted Average Sold Call ($/barrel) $ 45.78 $ 51.70 $ 51.85 $ 52.10 $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ 50.00 $ 50.00 NYMEX WTI Purchased Puts Average Volume Per Day (barrels) 1,667 Weighted Average Purchased Put Price ($/barrel) $ 55.00 NYMEX WTI Sold Puts Average Volume Per Day (barrels) 556 11,538 5,707 5,707 Weighted Average Sold Put ($/barrel) $ 26.50 $ 36.93 $ 35.14 35.14 MEH-NYMEX WTI Crude Basis Swaps Average Volume Per Day (barrels) 8,889 Weighted Average Swap Price ($/barrel) $ 1.16 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (barrels) 14,444 13,187 13,043 13,043 Weighted Average Swap Price ($/barrel) $ (0.18) $ 0.07 $ 0.07 $ 0.07 NYMEX HH Collars Average Volume Per Day (MMBtus) 10,000 9,890 9,783 9,783 Weighted Average Purchased Put Price ($/MMBtu) $ 2.607 $ 2.607 $ 2.607 $ 2.607 Weighted Average Sold Call ($/MMBtu) $ 3.117 $ 3.117 $ 3.117 $ 3.117 NYMEX HH Sold Puts Average Volume Per Day (MMBtus) 6,667 6,593 6,522 6,522 Weighted Average Sold Put Strike ($/MMBtu) $ 2.000 $ 2.000 $ 2.000 $ 2.000 As of December 31, 2020, we were unhedged with respect to NGL production.
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 and premiums received (paid), net.” The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2020 2019 2018 Interest rate swap losses recognized in the Consolidated Statements of Operations $ (7,510) $ — $ — Commodity gains (losses) recognized in the Consolidated Statements of Operations 95,932 (68,131) 37,427 $ 88,422 $ (68,131) $ 37,427 Interest rate cash settlements recognized in the Consolidated Statements of Cash Flows $ (2,210) $ — $ — Commodity cash settlements and premiums received (paid) recognized in the Consolidated Statements of Cash Flows 80,297 (4,136) (48,291) $ 78,087 $ (4,136) $ (48,291)
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, 2020 December 31, 2019 Derivative Derivative Derivative Derivative Type Balance Sheet Location Assets Liabilities Assets Liabilities Interest rate contracts Derivative assets/liabilities – current $ — $ 3,655 $ — $ — Commodity contracts Derivative assets/liabilities – current 78,793 81,772 4,131 23,450 Interest rate contracts Derivative assets/liabilities – noncurrent — 1,645 — — Commodity contracts Derivative assets/liabilities – noncurrent 25,449 26,789 2,750 3,385 $ 104,242 $ 113,861 $ 6,881 $ 26,835

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 Oil and gas properties: Proved $ 1,545,910 $ 1,409,219 Unproved 49,935 53,200 Total oil and gas properties 1,595,845 1,462,419 Other property and equipment 27,746 25,915 Total property and equipment 1,623,591 1,488,334 Accumulated depreciation, depletion and amortization (900,042) (367,909) $ 723,549 $ 1,120,425

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 Balance at beginning of period $ 4,934 $ 4,314 Changes in estimates 33 (2) Liabilities incurred 121 290 Liabilities settled — (67) Acquisitions of properties 16 83 Accretion expense 357 316 Balance at end of period $ 5,461 $ 4,934

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 December 31, 2019 Principal Unamortized Discount and Issuance Costs 1, 2 Principal Unamortized Discount and Issuance Costs 1, 2 Credit facility $ 314,400 $ 362,400 Second lien term loan 200,000 $ 4,903 200,000 $ 7,372 Totals 514,400 4,903 562,400 7,372 Less: Unamortized discount (“OID”) 2 (1,604) (2,415) Less: Unamortized deferred issuance costs 1, 2 (3,299) (4,957) Long-term debt, net $ 509,497 $ 555,028

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Current income taxes (benefit) Federal $ (1,236) $ (1,236) $ (2,471) State 357 — — (879) (1,236) (2,471) Deferred income taxes (benefit) Federal 1,236 1,236 2,471 State (2,660) 2,137 523 (1,424) 3,373 2,994 $ (2,303) $ 2,137 $ 523
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 expense (benefit) for the periods presented: Year Ended December 31, 2020 2019 2018 Computed at federal statutory rate $ (65,701) (21.0) % $ 15,272 21.0 % $ 47,315 21.0 % State income taxes, net of federal income tax benefit (1,856) (0.6) % 1,494 2.1 % 1,743 0.8 % Change in valuation allowance 64,062 20.5 % (14,240) (19.6) % (48,820) (21.7) % Other, net 1,192 0.4 % (389) (0.5) % 285 0.1 % $ (2,303) (0.7) % $ 2,137 3.0 % $ 523 0.2 %
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, 2020 2019 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 180,531 $ 175,221 Alternative minimum tax (“AMT”) credit carryforwards — 1,236 Asset retirement obligations 1,188 1,073 Pension and postretirement benefits 301 340 Share-based compensation 467 880 Fair value of derivative instruments 2,737 4,191 Interest expense limitation — 11,463 ROU assets 564 — Other 1,484 2,441 187,272 196,845 Less: Valuation allowance (179,006) (114,939) Total net deferred tax assets 8,266 81,906 Deferred tax liabilities: Property and equipment 7,728 83,330 ROU obligations 538 — Total deferred tax liabilities 8,266 83,330 Net deferred tax liabilities $ — $ (1,424)

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020	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 the dates presented: December 31, 2020 2019 ROU assets – operating leases $ 2,432 $ 2,740 Current operating lease obligations $ 936 $ 847 Noncurrent operating lease obligations 1,752 2,232 Total operating lease obligations $ 2,688 $ 3,079 Weighted-average remaining lease term – operating leases 3.1 years 4.1 years Weighted-average discount rate – operating leases 3.24 % 5.97 % Maturities of operating lease obligations for the years ending December 31, 2021 $ 936 2022 874 2023 872 2024 146 Total undiscounted lease payments 2,828 Less: imputed interest (140) Total operating lease obligations $ 2,688
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 periods presented: Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 943 $ 659 ROU assets obtained in exchange for operating lease obligations 1 $ 388 $ 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 periods presented: Year Ended December 31, 2020 2019 Operating lease cost $ 979 $ 773 Short-term lease cost 23,721 36,202 Variable lease cost 21,932 23,762 Less: Amounts charged as drilling costs 1 (20,708) (33,354) Total lease cost recognized in the Consolidated Statement of Operations 2 $ 25,924 $ 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 $11.2 million and $12.1 million recognized in GPT, $13.8 million and $14.5 million recognized in Lease operating expense (“LOE”) and $1.0 million and $0.8 million recognized in G&A for the years ended December 31, 2020 and 2019, respectively.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 Fair Value Fair Value Measurement Classification Description Measurement Level 1 Level 2 Level 3 Assets: Commodity derivative assets – current $ 78,793 $ — $ 78,793 $ — Commodity derivative assets – noncurrent $ 25,449 $ — $ 25,449 $ — Liabilities: Interest rate swap liabilities - current $ (3,655) $ — $ (3,655) $ — Interest rate swap liabilities - noncurrent $ (1,645) $ — $ (1,645) $ — Commodity derivative liabilities – current $ (81,772) $ — $ (81,772) $ — Commodity derivative liabilities – noncurrent $ (26,789) $ — $ (26,789) $ — 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) —

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Schedule of Loss Contingencies by Contingency	The following table sets forth our significant commitments as of December 31, 2020, by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Other Commitments 2021 $ 12,962 $ 317 2022 12,962 184 2023 12,962 — 2024 12,962 — 2025 12,962 — Thereafter 24,827 — Total $ 89,637 $ 501

Share-Based Compensation and _2

Share-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2020
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 Weighted-Average Balance at beginning of year 136,876 $ 49.76 Granted 281,382 $ 4.49 Vested (63,916) $ 43.30 Forfeited (35,062) $ 27.83 Balance at end of year 319,280 $ 13.56
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 2020, 2019 and 2017 are presented as follows: 2020 2019 Expected volatility 101.32% to 117.71% 49.9 % Dividend yield 0.0% 0.0% Risk-free interest rate 0.18% to 0.51% 1.66 %
Activity of Awarded Performance-based RSUs	The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Weighted-Average Grant Date Balance at beginning of year 79,914 $ 52.73 Granted 145,399 $ 7.79 Vested (31,146) $ 58.35 Forfeited (20,635) $ 55.99 Balance at end of year 173,532 $ 13.68

Interest Expense (Tables)

Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2020
Interest Expense [Abstract]
Components of Interest Expense	The following table summarizes the components of interest expense for the periods presented: Year Ended December 31, 2020 2019 2018 Interest on borrowings and related fees $ 29,851 $ 36,593 $ 32,164 Accretion of original issue discount 1 811 743 680 Amortization of debt issuance costs 2 3,339 2,611 2,736 Capitalized interest (2,744) (4,136) (9,118) $ 31,257 $ 35,811 $ 26,462 _____________________________________________ 1 Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 9).

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 2018 Net income (loss) – basic and diluted $ (310,557) $ 70,589 $ 224,785 Weighted-average shares – basic 15,176 15,110 15,059 Effect of dilutive securities 1 — 16 233 Weighted-average shares – diluted 15,176 15,126 15,292 _____________________________________________

Basis of Presentation (Details)

Basis of Presentation (Details) - USD ($)	Jan. 15, 2021	Jan. 31, 2021	Dec. 31, 2020	Jan. 14, 2021	Jan. 13, 2021	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 13, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Proceeds from Income Tax Refunds			$ 2,500,000
Severance Costs			200,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest			$ (212,838,000)			$ (520,745,000)	$ (447,355,000)	$ (221,639,000)
Subsequent Event [Line Items]
Common Stock, Par or Stated Value Per Share			$ 0.01			$ 0.01			$ 0.01
Preferred Stock, Shares Authorized			5,000,000
Common Stock, Shares, Issued			15,200,435			15,135,598
Preferred Stock, Shares Issued			0			0
Juniper Transactions
Subsequent Event [Line Items]
Professional Fees And Other Costs			$ 18,500,000
Juniper Transactions | Costs And Services Incurred In Current Period
Subsequent Event [Line Items]
Professional Fees And Other Costs			$ 5,000,000
Subsequent Event
Subsequent Event [Line Items]
Common Stock, Par or Stated Value Per Share					$ 0.01
Preferred Stock, Par or Stated Value Per Share					$ 0.01
Proceeds from Contributed Capital	$ 150,000,000
Asset Agreement - Preferred Shares	54,052.52
Asset Agreement - Common Shares	5,405,252
Contribution Agreement - Common Shares	17,142,857
Contribution Agreement - Preferred Shares	171,428.57
Common Units Placed in Indemnity Escrow	495,900
Preferred Shares Placed in Indemnity Escrow	4,959
Preferred Stock, Shares Authorized				300,000
Common Stock, Shares, Issued					22,597,757
Preferred Stock, Shares Issued					225,977.57
Common Unit, Issued	15,268,686				22,597,757
Transaction and Debt Issue Costs - Cash Paid	$ 17,800,000
Subsequent Event | Juniper Transactions
Subsequent Event [Line Items]
Transaction and Debt Issue Costs - Cash Paid	16,000,000
Professional Fees And Other Costs		$ 13,500,000
Reduction to capital contribution		9,300,000
Subsequent Event | Juniper Transactions | Contingent Transaction Costs To Be Paid Upon Closing
Subsequent Event [Line Items]
Professional Fees And Other Costs		5,500,000
Reduction to capital contribution		5,500,000
Subsequent Event | Juniper Transactions | Other Contingent Fees And Costs
Subsequent Event [Line Items]
Professional Fees And Other Costs		8,000,000
Subsequent Event | Juniper Transactions | Stock Issuance Costs
Subsequent Event [Line Items]
Reduction to capital contribution		3,800,000
Subsequent Event | Juniper Transactions | General and Administrative Expense
Subsequent Event [Line Items]
Professional Fees And Other Costs		4,200,000
Subsequent Event | Liquidation Of Outstanding Advances Attributable To Lender
Subsequent Event [Line Items]
Transaction and Debt Issue Costs - Cash Paid	1,300,000
Subsequent Event | Revolving Credit Facility
Subsequent Event [Line Items]
Payment for Debt Extinguishment or Debt Prepayment Cost	80,500,000	80,500,000
Accrued Interest Paid	100,000
Transaction and Debt Issue Costs - Cash Paid	400,000
Subsequent Event | Second Lien Facility
Subsequent Event [Line Items]
Payment for Debt Extinguishment or Debt Prepayment Cost	50,000,000	50,000,000
Repayments of Debt		$ 1,300,000
Accrued Interest Paid	200,000
Transaction and Debt Issue Costs - Cash Paid	$ 1,400,000
Accounting Standards Update 2016-02
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest							$ 94,000
Accounting Standards Update 2014-09
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest								$ 2,659,000

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2020
Minimum [Member]
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	2 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	5 years
Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	3 years
Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	20 years
Gas Gathering and Processing Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life	15 years
Gas Gathering and Processing Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life	20 years

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Lessee, Lease, Description (Details)	Dec. 31, 2020
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 ($)	Jul. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)a	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Mar. 01, 2018USD ($)
Significant Acquisitions and Disposals
Capitalized Costs, Proved Properties				$ 3,700		$ 2,100	$ 4,100
Second Lien Facility						200,000	200,000
Property, Plant and Equipment, Gross						1,623,591	1,488,334
Asset Retirement Obligation				4,314		5,461	4,934
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	$ 300
Working Capital Adjustments, Net	1,300	1,300
Pre-Tax Operating Income Attributable to Assets Sold				(1,600)
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
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				400	$ 100	$ 500		96,978
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
Business Acquisition, Pro Forma Revenue				446,077
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax				$ 227,930
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares				$ 15.14
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares				$ 14.91
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual			$ 200

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of Goods and Services Sold		$ 22,050	$ 23,197	$ 18,626
Net Income (Loss) Available to Common Stockholders, Basic	$ 224,785	(310,557)	70,589	224,785
Customers		39,672	63,165
Joint interest partners		3,079	6,929
Other		8	674
Accounts Receivable, Gross, Current, Total		42,759	70,768
Less: Allowance for credit losses		(197)	(52)
Accounts receivable, net of allowance for doubtful accounts		42,562	70,716
Oil and Gas, Exploration and Production [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		251,741	434,713	402,485
Oil and Condensate [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		8,948	16,589	21,073
Natural Gas, Production [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Revenue from contract with customer		$ 10,103	$ 17,733	$ 15,972

Accounts Receivable and Major_4

Accounts Receivable and Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2020USD ($)Customer	Dec. 31, 2019USD ($)Customer	Jan. 01, 2020USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Customers	$ 39,672,000	$ 63,165,000
Retained earnings	9,354,000	319,987,000
Accounts Receivable, Allowance for Credit Loss	197,000	52,000
Accounts Receivable, Credit Loss Expense (Reversal)	69,000
Accounts Receivable, Allowance for Credit Loss, Writeoff	$ 0
Name of Major Customer [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Commodity Products, Number of Customers | Customer	20
Financing Receivable, Credit Risk Percentage	0.00%
Accounts Receivable, Allowance for Credit Loss	$ 0	0
Accounts Receivable, Credit Loss Expense (Reversal)	0
Accounts Receivable, Allowance for Credit Loss, Writeoff	$ 0
Joint Interest Partners, Mutual Operators [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Commodity Products, Number of Customers | Customer	2
Financing Receivable, Credit Risk Percentage	5.00%		0.00%
Accounts Receivable, Allowance for Credit Loss	$ 9,000	0
Accounts Receivable, Credit Loss Expense (Reversal)	9,000
Accounts Receivable, Allowance for Credit Loss, Writeoff	$ 0
Joint Interest Partners, Large Partners [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Commodity Products, Number of Customers | Customer	3
Financing Receivable, Credit Risk Percentage			1.00%
Accounts Receivable, Allowance for Credit Loss	$ 87,000	0
Accounts Receivable, Credit Loss Expense (Reversal)	27,000
Accounts Receivable, Allowance for Credit Loss, Writeoff	$ 0
Joint Interest Partners, All Others [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Commodity Products, Number of Customers | Customer	20
Financing Receivable, Credit Risk Percentage	10.00%		5.00%
Financing Receivable, Past Due	$ 200,000
Accounts Receivable, Allowance for Credit Loss	101,000	$ 52,000
Accounts Receivable, Credit Loss Expense (Reversal)	33,000
Accounts Receivable, Allowance for Credit Loss, Writeoff	0
Cumulative Effect, Period of Adoption, Adjustment [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Allowance for Credit Loss			$ 76,000
Cumulative Effect, Period of Adoption, Adjustment [Member] | Name of Major Customer [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Allowance for Credit Loss			0
Cumulative Effect, Period of Adoption, Adjustment [Member] | Joint Interest Partners, Mutual Operators [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Allowance for Credit Loss			0
Cumulative Effect, Period of Adoption, Adjustment [Member] | Joint Interest Partners, Large Partners [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Allowance for Credit Loss			60,000
Cumulative Effect, Period of Adoption, Adjustment [Member] | Joint Interest Partners, All Others [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Allowance for Credit Loss			$ 16,000
Cumulative Effect, Period of Adoption, Adjustment [Member] | Accounting Standards Update 2016-13
Accounts, Notes, Loans and Financing Receivable [Line Items]
Retained earnings	$ 100,000
Accounts Receivable | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	3	4
Revenues, major customers	$ 150,800,000	$ 354,600,000
Concentration risk, percentage	56.00%	76.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 72,300,000	$ 172,300,000
Concentration risk, percentage	27.00%	37.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 50,200,000	$ 84,600,000
Concentration risk, percentage	19.00%	18.00%
Accounts Receivable | Customer Concentration Risk | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 28,300,000	$ 50,700,000
Concentration risk, percentage	10.00%	11.00%
Accounts Receivable | Customer Concentration Risk | Major Customer Four [Domain]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 47,000,000
Concentration risk, percentage		10.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	47.00%	70.00%
Accounts receivable, major customers	$ 18,600,000	$ 44,500,000

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)CustomerEntity	Dec. 31, 2019USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Asset	$ 104,242	$ 6,881
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Asset	$ 4,300
Number Of Derivative Counterparty | Entity	8
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Underlying Basis	WTI
Commodity contracts | MEH [Member]
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Underlying Basis	MEH
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Number Of Derivative Counterparty | Customer	4
Derivative, Notional Amount	$ 300,000
Derivative, Average Fixed Interest Rate	136.00%

Commodity Derivative Positions

Commodity Derivative Positions (Detail)	Dec. 31, 2020bbl$ / bbl
First Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	45.78
Derivative, Nonmonetary Notional Amount | bbl	9,722
First Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	2.607
Derivative, Cap Price	3.117
Derivative, Nonmonetary Notional Amount | bbl	10,000
First Quarter 2021 [Member] [Domain] | Put Option [Member] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,667
Derivative, Swap Type, Average Fixed Price	2
First Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,889
Derivative, Swap Type, Average Fixed Price	54.38
First Quarter 2021 [Member] [Domain] | Purchased Put [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,667
Derivative, Swap Type, Average Fixed Price	55
First Quarter 2021 [Member] [Domain] | Basis Swap [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	8,889
Derivative, Swap Type, Average Fixed Price	1.16
First Quarter 2021 [Member] [Domain] | CMA Roll Basis Swap [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,444
Derivative, CMA Roll Basis Swap, Price	(0.18)
First Quarter 2021 [Member] [Domain] | Sold Put [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	556
Derivative, Swap Type, Average Fixed Price	26.50
Second Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	42.84
Derivative, Cap Price	51.70
Derivative, Nonmonetary Notional Amount | bbl	10,440
Second Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	2.607
Derivative, Cap Price	3.117
Derivative, Nonmonetary Notional Amount | bbl	9,890
Second Quarter 2021 [Member] [Domain] | Put Option [Member] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,593
Derivative, Swap Type, Average Fixed Price	2
Second Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,297
Derivative, Swap Type, Average Fixed Price	55.89
Second Quarter 2021 [Member] [Domain] | CMA Roll Basis Swap [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,187
Derivative, CMA Roll Basis Swap, Price	0.07
Second Quarter 2021 [Member] [Domain] | Sold Put [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,538
Derivative, Swap Type, Average Fixed Price	36.93
Third Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40.35
Derivative, Cap Price	51.85
Derivative, Nonmonetary Notional Amount | bbl	9,239
Third Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	2.607
Derivative, Cap Price	3.117
Derivative, Nonmonetary Notional Amount | bbl	9,783
Third Quarter 2021 [Member] [Domain] | Put Option [Member] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,522
Derivative, Swap Type, Average Fixed Price	2
Third Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	815
Derivative, Swap Type, Average Fixed Price	45.54
Third Quarter 2021 [Member] [Domain] | CMA Roll Basis Swap [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,043
Derivative, CMA Roll Basis Swap, Price	0.07
Third Quarter 2021 [Member] [Domain] | Sold Put [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	5,707
Derivative, Swap Type, Average Fixed Price	35.14
Fourth Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40.40
Derivative, Cap Price	52.10
Derivative, Nonmonetary Notional Amount | bbl	8,152
Fourth Quarter 2021 [Member] [Domain] | 2-Way Collars [Domain] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	2.607
Derivative, Cap Price	3.117
Derivative, Nonmonetary Notional Amount | bbl	9,783
Fourth Quarter 2021 [Member] [Domain] | Put Option [Member] | Natural Gas [Member]
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,522
Derivative, Swap Type, Average Fixed Price	2
Fourth Quarter 2021 [Member] [Domain] | Swap [Member] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	815
Derivative, Swap Type, Average Fixed Price	45.54
Fourth Quarter 2021 [Member] [Domain] | CMA Roll Basis Swap [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,043
Derivative, CMA Roll Basis Swap, Price	0.07
Fourth Quarter 2021 [Member] [Domain] | Sold Put [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	5,707
Derivative, Swap Type, Average Fixed Price	35.14
First Quarter 2022 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,917
Second Quarter 2022 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,885
Third Quarter 2022 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,853
Fourth Quarter 2022 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,853
First Quarter 2023 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,917
Second Quarter 2023 [Domain] | 2-Way Collars [Domain] | Crude Oil
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Floor Price	40
Derivative, Cap Price	50
Derivative, Nonmonetary Notional Amount | bbl	2,855

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Commodity gains (losses) recognized in the Consolidated Statements of Operations	$ 88,422,000	$ (68,131,000)	$ 37,427,000
Cash Settlements Interest Rate Swap Operating Activities, Net	(2,210,000)	0	0
Cash Settlements Commodity Operating Activities	80,297,000	(4,136,000)	(48,291,000)
Commodity cash settlements and premiums received (paid) recognized in the Consolidated Statements of Cash Flows	78,087,000	(4,136,000)	(48,291,000)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	(7,510,000)	0	0
Gain (Loss) on Commodity Derivative Instruments	$ (95,932,000)	$ 68,131,000	$ (37,427,000)

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivatives	$ 88,422,000	$ (68,131,000)	$ 37,427,000
Commodity derivative assets – current	78,793,000	4,131,000
Derivative assets, noncurrent	25,449,000	2,750,000
Derivative liabilities, noncurrent	28,434,000	3,385,000
Derivative Asset	104,242,000	6,881,000
Derivative liabilities, current	85,427,000	23,450,000
Derivative liabilities	113,861,000	26,835,000
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative Asset	4,300,000
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	78,793,000	4,131,000
Derivative liabilities, current	81,772,000	23,450,000
Commodity contracts | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	25,449,000	2,750,000
Derivative liabilities, noncurrent	26,789,000	3,385,000
Interest Rate Swap | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	0	0
Derivative liabilities, current	3,655,000	0
Interest Rate Swap | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	0	0
Derivative liabilities, noncurrent	1,645,000	0
Fair Value, Measurements, Recurring | Commodity contracts
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	78,793,000	4,131,000
Derivative assets, noncurrent	25,449,000	2,750,000
Derivative liabilities, noncurrent	26,789,000	3,385,000
Derivative liabilities, current	(81,772,000)	$ (23,450,000)
Fair Value, Measurements, Recurring | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative liabilities, noncurrent	1,645,000
Derivative liabilities, current	$ (3,655,000)

Summary of Property and Equipme

Summary of Property and Equipment (Detail)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2020USD ($)$ / bbl	Sep. 30, 2020USD ($)	Dec. 31, 2020USD ($)$ / bbl	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Abstract]
Proved Oil and Gas Property, Full Cost Method	$ 1,545,910,000		$ 1,545,910,000	$ 1,409,219,000
Undeveloped Leasehold Costs Transferred			8,300,000	16,800,000
Interest Costs Capitalized			$ 2,700,000	$ 4,100,000	$ 9,100,000
Amortization Expense Per Physical Unit of Production | $ / bbl	15.83		15.83	17.25	16.11
Unproved Oil and Gas Property excluded	$ 49,900,000		$ 49,900,000	$ 53,200,000
Wells-in-progress	1,200,000		1,200,000
Asset Impairment Charges	120,300,000	$ 271,500,000	391,849,000	0	$ 0
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	2,200,000		2,200,000	1,600,000	2,000,000	$ 44,200,000
Capitalized Interest Remaining	1,100,000		1,100,000
Capitalized Costs, Proved Properties	2,100,000		2,100,000	4,100,000	$ 3,700,000
Oil and gas properties:
Unproved Oil and Gas Property, Full Cost Method	49,935,000		49,935,000	53,200,000
Oil and Gas Property, Full Cost Method, Gross	1,595,845,000		1,595,845,000	1,462,419,000
Other property and equipment	27,746,000		27,746,000	25,915,000
Total property and equipment	1,623,591,000		1,623,591,000	1,488,334,000
Accumulated depreciation, depletion and amortization	(900,042,000)		(900,042,000)	(367,909,000)
Property and equipment, net (successful efforts method)	$ 723,549,000		$ 723,549,000	$ 1,120,425,000

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligations which are Included in Other Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 4,934	$ 4,314
Changes in estimates	33	(2)
Liabilities incurred	121	290
Liabilities settled	0	(67)
Acquisitions of properties	(16)	(83)
Accretion expense	357	316
Balance at end of period	$ 5,461	$ 4,934

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Credit facility	$ 314,400	$ 362,400
Second Lien Facility	200,000	200,000
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums	4,903	7,372
Debt Instrument, Unamortized Discount	(1,604)	(2,415)
Unamortized Debt Issuance Expense	(3,299)	(4,957)
Long-term Debt	514,400	562,400
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	$ 509,497	$ 555,028
Second Lien Facility
Debt Instrument [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR	7.25%
Second Lien Facility, Interest Rate	8.00%

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Jan. 15, 2021USD ($)	Jan. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	May 03, 2019USD ($)
Debt Disclosure [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Gross			$ 100,000	$ 2,600,000
Required covenant, current ratio			1
Second Lien Facility			$ 200,000,000	200,000,000
Debt Instrument, Discounted Percentage			98.00%
Accelerated Deferred Debt Issuance Cost			$ 900,000
Anti-hoarding provision, maximum cash			25,000,000
Subsequent Event
Debt Disclosure [Line Items]
Amortization Payment		$ 1,875,000
Credit Facility Availability		25.00%
Revolving Credit Facility
Debt Disclosure [Line Items]
Maximum borrowing capacity			$ 375,000,000		$ 1,000,000,000
Letter of credit amount outstanding				$ 400,000
Line of Credit Facility, Interest Rate at Period End			3.40%
Required covenant, debt to EBITDAX ratio			3.50
Line of Credit Facility, Current Borrowing Capacity			$ 350,000,000
Revolving Credit Facility | Subsequent Event
Debt Disclosure [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Gross		$ 400,000
Required covenant, debt to EBITDAX ratio		2
Payment for Debt Extinguishment or Debt Prepayment Cost	$ 80,500,000	$ 80,500,000
Revolving Credit Facility | Minimum [Member]
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR			1.50%
Revolving Credit Facility | Maximum [Member]
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR			2.50%
Credit facility interest rate option two, applicable margin rate			3.50%
Commitment fees for undrawn credit facility			0.50%
Second Lien Facility
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR			7.25%
Credit facility interest rate option two, applicable margin rate			8.25%
Second Lien Facility, Initial Interest Rate			8.34%
Second Lien Facility, Effective Interest Rate			9.89%
Interest Rate Floor			1.00%
Second Lien Facility | Interest Payable One [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			1 month
Second Lien Facility | Interest Payable Two [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			3 months
Second Lien Facility | Interest Payable Three [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			6 months
Second Lien Facility | Subsequent Event
Debt Disclosure [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Gross		$ 1,400,000
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		8.25%
Credit facility interest rate option two, applicable margin rate		9.25%
Repayments of Debt		$ 1,300,000
Asset Coverage Ratio		1.25
Payment for Debt Extinguishment or Debt Prepayment Cost	$ 50,000,000	$ 50,000,000
Write off Deferred Debit Issuance and Original Issuance Costs		$ 1,300,000
First Lien [Member]
Debt Disclosure [Line Items]
Required covenant, debt to EBITDAX ratio			2.50
Letter of Credit
Debt Disclosure [Line Items]
Maximum borrowing capacity			$ 25,000,000
Year 1 | Second Lien Facility
Debt Disclosure [Line Items]
Prepayment Premium			102.00%
Year 2 | Second Lien Facility
Debt Disclosure [Line Items]
Prepayment Premium			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, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Federal	$ (1,236)	$ (1,236)	$ (2,471)
Current State and Local Tax Expense (Benefit)	357	0	0
Current Income Tax Expense (Benefit)	(879)	(1,236)	(2,471)
Current income tax expense (benefit), total	(879)	(1,236)	(2,471)
Deferred Federal Income Tax Expense (Benefit)	1,236	1,236	2,471
Deferred State and Local Income Tax Expense (Benefit)	(2,660)	2,137	523
Deferred income tax benefit, total	(1,424)	3,373	2,994
Income tax benefit	$ (2,303)	$ 2,137	$ 523

Income Taxes Reconciliation (De

Income Taxes Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ (65,701)	$ (15,272)	$ (47,315)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	1,856	(1,494)	(1,743)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	64,062	(14,240)	(48,820)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	1,192	(389)	285
Income tax benefit	$ (2,303)	$ 2,137	$ 523
Effective Income Tax Rate Reconciliation, Percent	(0.70%)	3.00%	0.20%
Computed at federal statutory rate	(21.00%)	(21.00%)	(21.00%)
State income taxes, net of federal income tax benefit	(0.60%)	2.10%	0.80%
Deferred Federal Income Tax Expense (Benefit)	$ 1,236	$ 1,236	$ 2,471
Change in valuation allowance	20.50%	(19.60%)	(21.70%)
Other, net	0.40%	(0.50%)	0.10%
Computed at federal statutory rate	21.00%	21.00%	21.00%

Summary of Principal Components

Summary of Principal Components of Net Deferred Income Tax Liability (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Deferred income taxes	$ 0	$ 1,424
Deferred Tax Assets, Operating Loss Carryforwards	180,531	175,221
Total net deferred tax assets	8,266	81,906
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	1,188	1,073
Deferred Tax Liabilities, Property, Plant and Equipment	7,728	83,330
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Postretirement Benefits	301	340
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	467	880
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	0	1,236
Deferred Tax Liabilities, ROU Obligations	538	0
Less:  Valuation allowance	(179,006)	(114,939)
Deferred Tax Asset, Interest Carryforward	0	11,463
Deferred Tax Assets, Other	1,484	2,441
Deferred Tax Assets, ROU Assets	564	0
Deferred Tax Assets, Gross	187,272	196,845
Deferred Tax Assets, Derivative Instruments	2,737	4,191
Deferred Tax and Other Liabilities, Noncurrent	$ 8,266	$ 83,330

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Valuation Allowance [Line Items]
Computed at federal statutory rate	21.00%	21.00%	21.00%
Income taxes receivable	$ 0	$ 1,236,000	$ 2,500,000
Deferred State and Local Income Tax Expense (Benefit)	(2,660,000)	2,137,000	523,000
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	1,192,000	(389,000)	285,000
Liabilities for unrecognized tax benefits	0	0
Deferred Tax Assets, Valuation Allowance	179,006,000	114,939,000
Income Tax Examination, Penalties and Interest Expense	$ 0	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Percent	(0.70%)	3.00%	0.20%
Deferred Federal Income Tax Expense (Benefit)	$ 1,236,000	$ 1,236,000	$ 2,471,000
Federal	(1,236,000)	(1,236,000)	$ (2,471,000)
Deferred income taxes	0	1,424,000
Deferred Tax and Other Liabilities, Noncurrent	8,266,000	$ 83,330,000
Federal
Valuation Allowance [Line Items]
Operating Loss Carryforwards	638,600,000
Federal, State and Local Tax Jurisdictions
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance	$ 179,000,000

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Lessee, Lease, Description [Line Items]
Operating Lease, Payments		$ 943	$ 659
Operating Lease, Cost		979	773
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability		388	3,325
Lease, Cost		25,924	27,383
Short-term Lease, Cost		23,721	36,202
Variable Lease, Cost		21,932	23,762
Amounts charged as dilling costs		(20,708)	(33,354)
Operating Lease, Liability, Current		$ 936	$ 847
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent
Operating Lease, Liability, Noncurrent		$ 1,752	$ 2,232
Operating Lease, Weighted Average Remaining Lease Term		3 years 1 month 6 days	4 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent		3.24%	5.97%
Lessee, Operating Lease, Liability, Payments, Due Next Rolling Twelve Months		$ 936
Lessee, Operating Lease, Liability, Payments, Due Year Two		874
Lessee, Operating Lease, Liability, Payments, Due Year Three		872
Lessee, Operating Lease, Liability, Payments, Due Year Four		146
Lessee, Operating Lease, Liability, Payments, Due		2,828
Lessee, Operating Lease, Liability, Undiscounted Excess Amount		$ (140)
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]		us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent	us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent
Operating Lease, Liability		$ 2,688	$ 3,079
Operating Leases, Rent Expense, Net				$ 2,700
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability, During the Year			800
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]		us-gaap:OtherAssetsNoncurrent
Other Noncurrent Assets
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset		$ 2,432	2,740
Accounting Standards Update 2019-01 [Member]
Lessee, Lease, Description [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 2,500
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost		12,100	11,200
Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost		13,800	14,500
General and Administrative Expense
Lessee, Lease, Description [Line Items]
Lease, Cost		$ 1,000	$ 800

Supplemental Balance Sheet De_2

Supplemental Balance Sheet Detail (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Prepaid and other current assets:
Inventory, Net	$ 3,856,000	$ 2,989,000
Prepaid Expense, Current	15,189,000	1,469,000
Drilling and Completion Prepayment	13,600,000
Other current assets	19,045,000	4,458,000
Other assets:
Debt Issuance Costs, Noncurrent, Net	2,349,000	3,952,000
Other	127,000	32,000
Accounts payable and accrued liabilities:
Trade accounts payable	7,055,000	30,098,000
Accounts Payable, Other, Current	16,088,000	18,832,000
Accrued Royalties, Current	26,615,000	44,537,000
Production, ad valorem and other taxes	3,094,000	3,244,000
Accrued Expenses - Juniper Transaction	3,500,000
Compensation-related	4,222,000	5,272,000
Interest Payable, Current	504,000	730,000
Operating Lease, Liability, Current	936,000	847,000
Other Accrued Liabilities, Current	4,254,000	2,264,000
Other liabilities:
Asset Retirement Obligations, Noncurrent	5,461,000	4,934,000
Operating Lease, Liability, Noncurrent	1,752,000	2,232,000
Liability, Defined Benefit Pension Plan, Noncurrent	865,000	873,000
Postretirement health care benefit obligations	$ 284,000	$ 343,000

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Assets:
Commodity derivative assets – current	$ 78,793	$ 4,131
Derivative assets	25,449	2,750
Liabilities:
Derivative liabilities, current	85,427	23,450
Derivative liabilities, noncurrent	(28,434)	(3,385)
Fair Value, Measurements, Recurring | Commodity contracts
Assets:
Commodity derivative assets – current	78,793	4,131
Derivative assets	25,449	2,750
Liabilities:
Derivative liabilities, current	(81,772)	(23,450)
Derivative liabilities, noncurrent	(26,789)	(3,385)
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	78,793	4,131
Derivative assets	25,449	2,750
Liabilities:
Derivative liabilities, current	(81,772)	(23,450)
Derivative liabilities, noncurrent	(26,789)	(3,385)
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
Fair Value, Measurements, Recurring | Interest Rate Swap
Liabilities:
Derivative liabilities, current	(3,655)
Derivative liabilities, noncurrent	(1,645)
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 1
Liabilities:
Derivative liabilities, current	0
Derivative liabilities, noncurrent	0
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 2
Liabilities:
Derivative liabilities, current	(3,655)
Derivative liabilities, noncurrent	(1,645)
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 3
Liabilities:
Derivative liabilities, current	0
Derivative liabilities, noncurrent	$ 0
Crude Oil | Commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Underlying Basis	WTI
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	12 Months Ended
	Dec. 31, 2020USD ($)
Commitments and Contingencies Disclosure [Line Items]
Number of drilling rigs	2
Commitments
Commitment length	5 years
Estimated Litigation Liability, Current	$ 100
Gathering and Intermediate Transportation
Commitments
2020	12,962
2021	12,962
2022	12,962
2023	12,962
2024	12,962
Thereafter	24,827
Total	89,637
Other Commitments
Commitments
2020	317
2021	184
2022	0
2023	0
2024	0
Thereafter	0
Total	$ 501

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2021	Dec. 31, 2020USD ($)bbl	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Line Items]
Commitment length		5 years
Number of drilling rigs		2
Minimum commitment		8,000
Estimated Litigation Liability, Current | $		$ 100
Asset retirement obligations | $		$ 5,461	$ 4,934	$ 4,314
Subsequent Event
Commitments and Contingencies Disclosure [Line Items]
Period to give notice to termination drilling rig agreement	30 days
Nuevo Dos Gathering and Transportation, LLC [Member] | Crude Oil Storage Capacity [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment		180,000
Nuevo Dos Gathering and Transportation, LLC [Member] | Crude Oil Storage Capacity With Downstream Interstate Pipeline [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment		90,000
Nuevo Dos Gathering and Transportation, LLC [Member] | Tank Capacity [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment		70,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate [Member] | Crude Oil Storage Capacity With Downstream Interstate Pipeline [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment		62,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate [Member] | Additional Crude Oil Storage Capacity With Downstream Interstate Pipeline
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment		120,000
Gathering and Intermediate Transportation
Commitments and Contingencies Disclosure [Line Items]
Contractual Commitments Future Minimum Payments Due | $		$ 89,637
Contractual Commitments Future Minimum Payments Due Current | $		$ 12,962

Shareholders' Equity - Addition

Shareholders' Equity - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Equity [Abstract]
Preferred stock, shares outstanding	0	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	$ (72)	$ (141)	$ 82
Common Stock, Shares, Issued	15,200,435	15,135,598
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Authorized	5,000,000
Accumulated other comprehensive loss	$ (131)	$ (59)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax	72	141	(82)
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	100	100	100
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	$ (310,629)	$ 70,448	$ 224,867

Share-Based Compensation and _3

Share-Based Compensation and Other Benefit Plans - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Accelerated Cost		$ 700	$ 200	$ 600
Share-based compensation (equity-classified)	$ (4,600)	(3,284)	(4,082)	(4,618)
Defined Contribution Plan, Cost		900	900	600
Compensation		4,222	5,272
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		100	$ 100	100
Officer Severance Costs		500
Executive Transition Costs		$ 1,200
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		641,997
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, Number of Shares Available for Grant		145,399	15,066
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		258,991
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount		$ 1,500
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition		1 year 3 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		145,399
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 7.79
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
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		$ 3,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		281,382
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 4.49
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value		$ 2,800	$ 3,000	3,300
Share-based Payment Arrangement, Tranche One [Member] | 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, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 34.02
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		$ 2.40
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		$ 16.02
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		$ 1,300	1,300	$ 1,300
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		$ 200	$ 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 ($)	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Severance Costs		$ 200,000
Share-based Payment Arrangement, Accelerated Cost		700,000	$ 200,000	$ 600,000
Defined Contribution Plan, Cost		900,000	900,000	600,000
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		100,000	100,000	100,000
Share-based compensation	$ 4,600,000	3,284,000	$ 4,082,000	4,618,000
Separation Agreement, Consulting Fees				300,000
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		$ 3,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		281,382
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
Performance Restricted Stock Units [Domain]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount		$ 1,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		145,399
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition		1 year 3 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		145,399	15,066
Other Pension, Postretirement and Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Liability, Defined Benefit Plan, Noncurrent		$ 1,300,000	$ 1,300,000	1,300,000
Pension and Other Postretirement Benefits Cost (Reversal of Cost)		$ 100,000	$ 100,000	$ 100,000

Share-Based Compensation and _5

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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 2.8	$ 3	$ 3.3
Number of shares
Balance at beginning of year (in shares)	136,876
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	281,382
Vested (in shares)	(63,916)
Forfeited (in shares)	(35,062)
Balance at end of year (in shares)	319,280	136,876
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 49.76
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	4.49
Vested (in dollars per share)	43.30
Forfeited (in dollars per share)	27.83
Balance at end of year (in dollars per share)	$ 13.56	$ 49.76
Performance Restricted Stock Units [Domain]
Number of shares
Balance at beginning of year (in shares)	79,914
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	145,399
Vested (in shares)	(31,146)
Forfeited (in shares)	(20,635)
Balance at end of year (in shares)	173,532	79,914
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 52.73
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	7.79
Vested (in dollars per share)	58.35
Forfeited (in dollars per share)	55.99
Balance at end of year (in dollars per share)	$ 13.68	$ 52.73
Performance Restricted Stock Units [Domain] | Share-based Payment Arrangement, Tranche One [Member]
Weighted-Average Grant Date Fair Value
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
Performance Shares [Member]
Weighted-Average Grant Date Fair Value
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%	0.00%
Risk-free interest rate, max	0.51%
Risk-free interest rate, min	0.18%	1.66%
Expected volatility, min	101.32%	49.90%
Expected volatility, max	117.71%
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%
Minimum [Member] | Performance Restricted Stock Units [Domain] | Share-based Payment Arrangement, Tranche One [Member]
Weighted-Average Grant Date Fair Value
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 2.40
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%
Maximum [Member] | Performance Restricted Stock Units [Domain] | Share-based Payment Arrangement, Tranche One [Member]
Weighted-Average Grant Date Fair Value
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 16.02

Components of Interest Expense

Components of Interest Expense (Detail) - USD ($)	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Interest Expense [Abstract]
Interest expense	$ 26,462,000	$ 31,257,000	$ 35,811,000	$ 26,462,000
Amortization of debt issuance costs 2	2,736,000	3,339,000	2,611,000
Amortization of Debt Discount (Premium)	680,000	811,000	743,000
Interest on borrowings and related fees	32,164,000	29,851,000	36,593,000
Interest Paid, Capitalized, Investing Activities	$ 9,118,000	2,744,000	$ 4,136,000
Accelerated Deferred Debt Issuance Cost		$ 900,000

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net loss attributable to common shareholders		$ 224,785	$ (310,557)	$ 70,589	$ 224,785
Weighted-average shares – basic		15,059	15,176	15,110	15,059
Effect of dilutive securities	[1]	233	0	16
Weighted average shares outstanding – diluted		15,292	15,176	15,126	15,292
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount			100
[1]