SilverBow Resources (SBOW) 10-Q 5 Aug 21 2021 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2021	Jul. 30, 2021
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2021
Entity File Number	1-8754
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-3940661
Entity Address, Address Line One	920 Memorial City Way
Entity Address, Address Line Two	Suite 850
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	281
Local Phone Number	874-2700
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	SBOW
Security Exchange Name	NYSE
Entity Filer Category	Non-accelerated Filer
Document Quarterly Report	true
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding		12,197,736
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 2,063	$ 2,118
Accounts receivable, net	25,957	25,850
Fair value of commodity derivatives	736	4,821
Other current assets	3,055	2,184
Total Current Assets	31,811	34,973
Property and Equipment:
Property and Equipment, full cost method	1,402,202	1,343,373
Less - Accumulated depreciation, depletion, and amortization	(830,749)	(801,279)
Net Furniture, Fixtures and other equipment	571,453	542,094
Right of Use Assets	16,609	4,366
Fair value of long-term commodity derivatives	1	281
Other Long-Term Assets	3,069	1,421
Total Assets	622,943	583,135
Current Liabilities:
Accounts payable and accrued liabilities	23,887	26,991
Fair value of commodity derivatives	45,369	8,171
Accrued capital costs	12,114	7,324
Accrued interest	955	983
Current lease liability	6,029	3,473
Undistributed oil and gas revenues	13,570	11,098
Total Current Liabilities	101,924	58,040
Long-Term Debt	393,446	424,905
Non-current Lease Liability	10,670	951
Deferred Tax Liabilities	303	303
Asset Retirement Obligation	4,586	4,533
Fair value of long-term commodity derivatives	10,286	2,946
Other Long-Term Liabilities	490	424
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	124	121
Additional paid-in capital	300,088	297,712
Treasury stock held, at cost	(2,975)	(2,372)
Retained earnings (Accumulated deficit)	(195,999)	(204,428)
Total Stockholders' Equity (Deficit)	101,238	91,033
Total Liabilities and Stockholders' Equity	$ 622,943	$ 583,135

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Capitalized Costs, unproved property balance	$ 24,312	$ 28,090
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares issued	12,388,208	12,053,763
Common stock, shares outstanding	12,196,978	11,936,679
Treasury stock shares held, at cost	191,230	117,084

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Income Statement [Abstract]
Oil and gas sales	$ 69,861	$ 24,846	$ 156,602	$ 78,222
Costs and Expenses [Abstract]
General and administrative, net	4,834	6,180	9,616	12,093
Depreciation, depletion, and amortization	16,039	13,716	29,431	37,156
Accretion of asset retirement obligation	74	88	148	173
Lease operating costs	5,515	5,000	11,789	10,812
Workovers	76	0	90	0
Transportation and gas processing	6,206	4,554	11,262	11,197
Severance and other taxes	3,577	2,037	7,066	5,001
Write-down of oil and gas properties	0	260,342	0	355,948
Operating Expenses	36,321	291,917	69,402	432,380
Operating Income (Loss)	33,540	(267,071)	87,200	(354,158)
Net gain (loss) on commodity derivatives	(46,067)	(8,458)	(64,326)	79,829
Interest expense, net	(7,436)	(8,026)	(14,454)	(16,433)
Other Nonoperating Income (Expense)	12	(1)	9	107
Income (Loss) Before Income Taxes	(19,951)	(283,556)	8,429	(290,655)
Provision (Benefit) for Income Taxes	0	22,420	0	21,179
Net Income (Loss)	$ (19,951)	$ (305,976)	$ 8,429	$ (311,834)
Per Share Amounts-
Earnings Per Share, Basic	$ (1.64)	$ (25.69)	$ 0.70	$ (26.28)
Earnings Per Share, Diluted	$ (1.64)	$ (25.69)	$ 0.68	$ (26.28)
Weighted Average Shares Outstanding - Basic	12,190	11,910	12,110	11,868
Weighted Average Shares Outstanding - Diluted	12,190	11,910	12,379	11,868

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2019	$ 395,707	$ 119	$ 292,916	$ (2,282)	$ 104,954
Purchase of treasury shares	(83)	0	0	(83)	0
Vesting of share-based compensation	0	1	(1)	0	0
Amortization of share-based compensation	1,335	0	1,335	0	0
Net Income (Loss)	(5,858)	0	0	0	(5,858)
Ending Balance at Mar. 31, 2020	391,101	120	294,250	(2,365)	99,096
Beginning Balance at Dec. 31, 2019	395,707	119	292,916	(2,282)	104,954
Net Income (Loss)	(311,834)
Ending Balance at Jun. 30, 2020	86,351	120	295,479	(2,368)	(206,880)
Beginning Balance at Mar. 31, 2020	391,101	120	294,250	(2,365)	99,096
Shares issued from warrant exercise	0	0	0	0	0
Purchase of treasury shares	(3)	0	0	(3)	0
Vesting of share-based compensation	0	0	0	0	0
Amortization of share-based compensation	1,229	0	1,229	0	0
Net Income (Loss)	(305,976)	0	0	0	(305,976)
Ending Balance at Jun. 30, 2020	86,351	120	295,479	(2,368)	(206,880)
Beginning Balance at Dec. 31, 2020	91,033	121	297,712	(2,372)	(204,428)
Purchase of treasury shares	(488)	0	0	(488)	0
Vesting of share-based compensation	0	2	(2)	0	0
Amortization of share-based compensation	1,131	0	1,131	0	0
Net Income (Loss)	28,380	0	0	0	28,380
Ending Balance at Mar. 31, 2021	120,056	123	298,841	(2,860)	(176,048)
Beginning Balance at Dec. 31, 2020	91,033	121	297,712	(2,372)	(204,428)
Net Income (Loss)	8,429
Ending Balance at Jun. 30, 2021	101,238	124	300,088	(2,975)	(195,999)
Beginning Balance at Mar. 31, 2021	120,056	123	298,841	(2,860)	(176,048)
Purchase of treasury shares	(115)	0	0	(115)	0
Vesting of share-based compensation	0	1	(1)	0	0
Amortization of share-based compensation	1,248	0	1,248	0	0
Net Income (Loss)	(19,951)	0	0	0	(19,951)
Ending Balance at Jun. 30, 2021	$ 101,238	$ 124	$ 300,088	$ (2,975)	$ (195,999)

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - shares	3 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Mar. 31, 2020
Statement of Stockholders' Equity [Abstract]
Purchase of treasury stock (shares)	13,969	60,177	1,098	26,675
Vesting of share-based compensation (shares)	51,332	283,113	49,665	105,108
Warrants exercised (shares)			5

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Cash Flows from Operating Activities:
Net Income (Loss)	$ (19,951)	$ (305,976)	$ 8,429	$ (311,834)
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	16,039	13,716	29,431	37,156
Write-down of oil and gas properties	0	260,342	0	355,948
Accretion of asset retirement obligation	74	88	148	173	$ 354
Deferred income taxes			0	21,087
Stock-based compensation expenses			2,260	2,437
Loss (gain) on derivatives			64,326	(79,829)
Cash settlements on derivatives			(10,708)	67,496
Settlements of asset retirement obligations			(166)	(15)
Write off of Deferred Debt Issuance Cost			229	459
Other Noncash Income (Expense)			1,202	1,814
(Increase) decrease in accounts receivable and other current assets			(1,387)	14,293
Increase (decrease) in accounts payable and accrued liabilities			(502)	(10,137)
Increase (Decrease) in Income Taxes Payable			0	92
Increase (decrease) in accrued interest			(28)	(140)
Net Cash Provided by (Used in) Operating Activities			93,234	99,000
Cash Flows from Investing Activities:
Additions to property and equipment			(56,995)	(85,594)
Acquisition of oil and gas properties			(207)	(3,394)
Proceeds from Sale of Property, Plant, and Equipment			0	(4,752)
Payments on property sale obligations			(1,084)	(426)
Net Cash Provided by (Used in) Investing Activities			(58,286)	(84,662)
Cash Flows from Financing Activities:
Proceeds from bank borrowings			123,000	50,000
Payments of bank borrowings			(155,000)	(59,000)
Purchase of treasury shares			(603)	(86)
Payments of Debt Issuance Costs			(2,400)	0
Net Cash Provided by (Used in) Financing Activities			(35,003)	(9,086)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash			(55)	5,252
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 2,063	$ 6,610	2,063	6,610	$ 2,118	$ 1,358
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized			13,282	15,006
Changes in capital accounts payable and capital accruals			$ 1,307	$ (28,618)

General Information

General Information	6 Months Ended
	Jun. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Information	(1) General Information SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested. The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies Basis of Presentation . The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. COVID-19 . The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and into the first half of 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, and approximately $77 and $74 per barrel, respectively, on June 30, 2021. In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed volumes as of December 31, 2020. As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence was required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On August 3, 2021, we acquired additional working interest in 12 wells that we currently operate and additional acreage in Webb County for total aggregate consideration of approximately $24 million. Through July 30, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2021: Oil Derivative Contracts Total Volumes (Bbls) (1) Weighted-Average Price 2021 Contracts 3Q21 30,000 $ 70.75 3Q21 (2) 12,000 $ 72.76 4Q21 81,250 $ 66.69 2022 Contracts 1Q22 45,000 $ 63.37 2Q22 45,500 $ 62.00 3Q22 46,000 $ 60.81 4Q22 46,000 $ 59.75 (1) Bbl refers to one barrel of oil. (2) Transaction for a swap purchase to reduce overall hedge position. Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 610,000 $ 4.00 4Q21 1,240,000 $ 3.90 2022 Contracts 2Q22 3,795,000 $ 2.99 3Q22 4,140,000 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2022 Contracts 4Q22 1,380,000 $ 2.90 $ 3.34 2023 Contracts 1Q23 1,350,000 $ 2.95 $ 3.51 2Q23 2,275,000 $ 2.40 $ 2.84 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 45,000 $ 26.32 2Q22 45,500 $ 26.32 3Q22 46,000 $ 26.32 4Q22 46,000 $ 26.32 There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural 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 services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.9 million, respectively. For the six months ended June 30, 2021 and 2020, such internal costs capitalized totaled $2.3 million and $2.0 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,372,163 $ 1,310,008 Unproved oil and gas properties 24,312 28,090 Furniture, fixtures and other equipment 5,727 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (830,749) (801,279) Property and Equipment, Net $ 571,453 $ 542,094 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $260.3 million and $355.9 million for the three and six months ended June 30, 2020, respectively, on our oil and natural gas properties. There was no impairment for the three and six months ended June 30, 2021. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods. Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets. At June 30, 2021, our “Accounts receivable, net” balance included $23.9 million for oil and gas sales, $0.6 million due from joint interest owners, $1.0 million for severance tax credit receivables and $0.4 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.2 million and $0.9 million for the three months ended June 30, 2021 and 2020, respectively, and $2.4 million and $2.2 million for the six months ended June 30, 2021 and 2020, respectively. Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $22.4 million and $21.2 million for the three and six months ended June 30, 2020, respectively, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of June 30, 2021. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity. Revenue Recognition . Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended June 30, 2021 and 2020 and the six months ended June 30, 2021 and 2020 (in thousands): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Oil, natural gas and NGLs sales: Oil $ 15,890 $ 5,265 $ 33,356 $ 23,315 Natural gas 46,791 18,103 109,705 49,574 NGLs 7,180 1,478 13,541 5,333 Total $ 69,861 $ 24,846 $ 156,602 $ 78,222 Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2021 December 31, 2020 Trade accounts payable $ 8,736 $ 15,930 Accrued operating expenses 2,873 2,491 Accrued compensation costs 2,579 3,771 Asset retirement obligations – current portion 515 441 Accrued non-income based taxes 2,517 1,819 Accrued corporate and legal fees 143 150 Other payables 6,524 2,389 Total accounts payable and accrued liabilities $ 23,887 $ 26,991 Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2021 and 2020, we purchased 74,146 and 27,773 treasury shares, respectively, to satisfy withholding tax obligations arising upon the vesting of restricted shares.

Leases Leases (Notes)

Leases Leases (Notes)	6 Months Ended
	Jun. 30, 2021
Leases [Abstract]
Lessee, Operating Leases [Text Block]	(3) Leases The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2021, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term. Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 1,491 $ 118 $ 1,820 $ 2,302 Property, plant and equipment acquisitions - operating leases — 5 — 10 Total lease costs in property, plant and equipment additions $ 1,491 $ 123 $ 1,820 $ 2,312 Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating expenses - short-term leases $ 618 $ 650 $ 1,085 $ 900 Lease operating expenses - operating leases 1,106 1,433 2,270 2,870 General and administrative, net - operating leases 178 179 351 359 Total lease cost expensed $ 1,902 $ 2,262 $ 3,706 $ 4,129 The lease term and the discount rate related to the Company's leases are as follows: June 30, 2021 Weighted-average remaining lease term (in years) 3.1 Weighted-average discount rate 4.1 % As of June 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of June 30, 2021 2021 (Remaining) $ 3,462 2022 6,443 2023 5,642 2024 742 2025 742 Thereafter 856 Total undiscounted lease payments 17,887 Present value adjustment (1,188) Net operating lease liabilities $ 16,699 Supplemental cash flow information related to leases was as follows (in thousands): Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Cash paid for amounts included in the measurement of lease liabilities; Operating cash flows from operating leases $ 2,618 $ 3,225 Investing cash flows from operating leases $ — $ 10

Share-Based Compensation

Share-Based Compensation	6 Months Ended
	Jun. 30, 2021
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	(4) Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting. The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.2 million for both the three months ended June 30, 2021 and 2020 and $2.3 million and $2.4 million for the six months ended June 30, 2021 and 2020, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended June 30, 2021 and 2020 and $0.1 million for both the six months ended June 30, 2021 and 2020. We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. Stock Option Awards The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one five At June 30, 2021, we had $0.4 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2021: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 303,705 $ 27.73 Options forfeited (3,896) $ 16.96 Options expired (23,800) $ 23.25 Options outstanding, end of period 276,009 $ 28.12 Options exercisable, end of period 226,950 $ 28.53 Our outstanding stock option awards had $0.1 million measurable aggregate intrinsic value at June 30, 2021. At June 30, 2021, the weighted-average remaining contract life of stock option awards outstanding was 4.6 years and exercisable was 4.4 years. The total intrinsic value of stock option awards exercisable was less than $0.1 million for the six months ended June 30, 2021. Restricted Stock Units The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one As of June 30, 2021, we had $1.9 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 1.0 years. The following table provides information regarding RSU activity for the six months ended June 30, 2021: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 574,916 $ 9.02 RSUs granted 100,178 $ 8.33 RSUs forfeited (17,802) $ 11.09 RSUs vested (310,645) $ 9.02 RSUs outstanding, end of period 346,647 $ 8.71 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of three On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two As of June 30, 2021, we had $2.2 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.3 years while 23,800 shares vested during the six months ended June 30, 2021.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2021
Earnings Per Share [Abstract]
Earnings Per Share	(5) Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and six months ended June 30, 2021 and 2020 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69) Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 8,429 12,110 $ 0.70 $ (311,834) 11,868 $ (26.28) Dilutive Securities: RSU Awards 269 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 8,429 12,379 $ 0.68 $ (311,834) 11,868 $ (26.28) Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the three months ended June 30, 2021 and 2020 because they were antidilutive due to the net loss, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the six months ended June 30, 2021 because they were antidilutive, while 0.3 million stock options to purchase shares were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss. Less than approximately 0.1 million and 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended June 30, 2021 and 2020, respectively, because they were antidilutive due to the net loss, while 0.1 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, 2021 because they were antidilutive while 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, 2020 because they were antidilutive due to the net loss. There were no antidilutive shares of PSUs that could be converted to common shares for the three months ended June 30, 2021, while approximately 0.1 million shares of PSUs were not included for the three months ended June 30, 2020 because they were antidilutive due to the net loss, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2021 because they were antidilutive, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2021
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): June 30, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 198,000 $ 230,000 Second Lien Notes due 2024 200,000 200,000 398,000 430,000 Unamortized discount on Second Lien Notes due 2024 (1,157) (1,295) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,397) (3,800) Long-Term Debt, net $ 393,446 $ 424,905 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of June 30, 2021 and December 31, 2020, we had $3.0 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $198.0 million and $230.0 million as of June 30, 2021 and December 31, 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Seventh Amendment to the Credit Facility, effective April 16, 2021 (the “Seventh Amendment”), which among other things, (i) redetermined the borrowing base under the Credit Facility to $300 million (from $310 million), (ii) extended the maturity of our Credit Facility from April 19, 2022 to April 19, 2024; (iii) increased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iv) reduced the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (v) implemented a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (vi) increased the mortgage coverage and title requirements from 85% to 90%. The Credit Facility provides for a maximum credit amount of $600.0 million, subject to the current borrowing base of $300.0 million as of June 30, 2021. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. Maintaining or increasing our borrowing base under our Credit Facility is dependent on many factors, including commodity prices, our hedge positions , changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves. Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Effective April 16, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Credit Agreement provides for options in the event LIBOR is discontinued. The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 90% of estimated proved reserves of the Company and its subsidiary. The Credit Agreement contains the following financial covenants: • a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.00 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.00 to 1.00 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; and • a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter. As of June 30, 2021, the Company was in compliance with all financial covenants under the Credit Agreement. Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $2.8 million and $3.5 million for the three months ended June 30, 2021 and 2020, respectively, and $5.3 million and $6.9 million for the six months ended June 30, 2021 and 2020, respectively. There was no capitalized interest on our unproved properties for both the three months ended June 30, 2021 and 2020, respectively, and for both the six months ended June 30, 2021 and 2020, respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024. Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2021; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote. The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2021, the Company was in compliance with all financial covenants under the Second Lien. The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable. As of June 30, 2021, total net amounts recorded for the Second Lien were $195.4 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million for both the three months ended June 30, 2021 and 2020, respectively, and $9.2 million and $9.5 million for the six months ended June 30, 2021 and 2020, respectively.

Acquisitions and Dispositions A

Acquisitions and Dispositions Acquisitions and Dispostions	6 Months Ended
	Jun. 30, 2021
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions and Dispositions	(7) Acquisitions and Dispositions Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $1.1 million and $0.4 million was paid during the six months ended June 30, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of June 30, 2021.

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	(8) Price-Risk Management Activities Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended June 30, 2021 and 2020, the Company recorded losses of $46.1 million and losses of $8.5 million, respectively, on its commodity derivatives. During the six months ended June 30, 2021 and 2020, the Company recorded losses of $64.3 million and gains of $79.8 million, respectively. The Company made cash payments of $10.7 million and collected cash payments of $67.5 million for settled derivative contracts during the six months ended June 30, 2021 and 2020, respectively. Included in our collected cash payments during the six months ended June 30, 2020 was $38.3 million for monetized derivative contracts. At June 30, 2021 and December 31, 2020, there were $0.4 million and $0.8 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2021 and January 2021, respectively. At June 30, 2021 and December 31, 2020, we also had $5.1 million and $0.8 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in July 2021 and January 2021, respectively. The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At June 30, 2021, there was $0.7 million and less than $0.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $45.4 million and $10.3 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2020, there was $4.8 million and $0.3 million in current and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 million in current and long-term unsettled derivative liabilities, respectively. The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $54.9 million net fair value liability at June 30, 2021, and a $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 179,759 $ 51.19 4Q21 191,412 $ 53.60 2022 Contracts 1Q22 178,455 $ 45.77 2Q22 91,000 $ 54.00 3Q22 200,100 $ 47.05 4Q22 138,000 $ 53.20 2023 Contracts 1Q23 81,900 $ 55.70 Collar Contracts 2021 Contracts 3Q21 90,620 $ 34.34 $ 39.87 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 2023 Contracts 2Q23 36,400 $ 56.00 $ 63.20 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 330,000 $ 2.62 4Q21 290,000 $ 2.69 2022 Contracts 3Q22 2,100 $ 2.50 Collar Contracts 2021 Contracts 3Q21 8,185,175 $ 2.36 $ 2.82 4Q21 8,991,000 $ 2.61 $ 2.98 2022 Contracts 1Q22 8,465,000 $ 2.72 $ 3.36 2Q22 5,246,500 $ 2.15 $ 2.60 3Q22 4,899,000 $ 2.39 $ 2.72 4Q22 4,545,076 $ 2.41 $ 2.88 2023 Contracts 1Q23 4,297,000 $ 2.62 $ 3.11 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2021 Contracts 3Q21 10,120,000 $ (0.022) 4Q21 11,040,000 $ (0.013) 2022 Contracts 1Q22 6,300,000 $ 0.052 2Q22 2,730,000 $ (0.063) 3Q22 2,760,000 $ (0.063) 4Q22 2,760,000 $ (0.063) Oil Basis Swaps Total Volumes (Bbls) Weighted-Average Price 2021 Contracts 3Q21 262,200 $ 1.27 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 3Q21 253,000 $ (0.34) 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 216,000 $ 0.09 2Q22 218,400 $ 0.09 3Q22 220,800 $ 0.09 4Q22 220,800 $ 0.09 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2021 Contracts 3Q21 192,324 $ 24.26 4Q21 192,324 $ 24.26 2022 Contracts 1Q22 45,000 $ 23.52

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) Fair Value Measurements Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below). The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value: Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2021 and December 31, 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant June 30, 2021 Assets Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Basis Derivatives 0.4 — 0.4 — Liabilities Natural Gas Derivatives 22.8 — 22.8 — Natural Gas Basis Derivatives 1.6 — 1.6 — Oil Derivatives 25.7 — 25.7 — Oil Basis Derivatives 1.0 — 1.0 — NGL Derivatives 4.5 — 4.5 — December 31, 2020 Assets Natural Gas Derivatives 1.5 — 1.5 — Natural Gas Basis Derivatives 1.1 — 1.1 — Oil Derivatives 2.5 — 2.5 — Liabilities Natural Gas Derivatives 4.0 — 4.0 — Natural Gas Basis Derivatives 0.4 — 0.4 — Oil Derivatives 5.9 — 5.9 — Oil Basis Derivatives 0.8 — 0.8 — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Notes)	6 Months Ended
	Jun. 30, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(10) Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs upon initial recording, excluding salvage values. The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2020 and the six months ended June 30, 2021 (in thousands): Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974 Accretion expense 148 Liabilities incurred for new wells and facilities construction 292 Reductions due to plugged wells and facilities (157) Revisions in estimates (156) Asset Retirement Obligations as of June 30, 2021 $ 5,101 At June 30, 2021 and December 31, 2020, approximately $0.5 million and $0.4 million, respectively, of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies	6 Months Ended
	Jun. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(11) Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2021
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”), • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment	Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural 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 services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.9 million, respectively. For the six months ended June 30, 2021 and 2020, such internal costs capitalized totaled $2.3 million and $2.0 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs). The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,372,163 $ 1,310,008 Unproved oil and gas properties 24,312 28,090 Furniture, fixtures and other equipment 5,727 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (830,749) (801,279) Property and Equipment, Net $ 571,453 $ 542,094 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test	Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Accounts Receivable, Net	Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
Supervision Fees	Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations.
Income Taxes	Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $22.4 million and $21.2 million for the three and six months ended June 30, 2020, respectively, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of June 30, 2021. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity.
Revenue Recognition	Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2021 December 31, 2020 Trade accounts payable $ 8,736 $ 15,930 Accrued operating expenses 2,873 2,491 Accrued compensation costs 2,579 3,771 Asset retirement obligations – current portion 515 441 Accrued non-income based taxes 2,517 1,819 Accrued corporate and legal fees 143 150 Other payables 6,524 2,389 Total accounts payable and accrued liabilities $ 23,887 $ 26,991
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Treasury Stock	Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets.

Leases Leases (Policies)

Leases Leases (Policies)	6 Months Ended
	Jun. 30, 2021
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Leases The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2021, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Policies)	6 Months Ended
	Jun. 30, 2021
Share-based Payment Arrangement [Abstract]
Share-based Compensation, Option and Incentive Plans Policy	Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Policies)	6 Months Ended
	Jun. 30, 2021
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Earnings Per ShareBasic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and six months ended June 30, 2021 and 2020 are discussed below.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	6 Months Ended
	Jun. 30, 2021
Debt Disclosure [Abstract]
Debt Issuance Costs, Policy	Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings.

Price-Risk Management Price-R_2

Price-Risk Management Price-Risk Management (Policies)	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management Activities    Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Disclosures (Policies)	6 Months Ended
	Jun. 30, 2021
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments, Policy	Fair Value Measurements Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below). The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below). The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value: Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.

Asset Retirement Obligations _2

Asset Retirement Obligations Asset Retirement Obligations (Policies)	6 Months Ended
	Jun. 30, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy	Asset Retirement ObligationsLiabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs upon initial recording, excluding salvage values.

Commitments and Contingencies_2

Commitments and Contingencies Commitments and Contingencies (Policies)	6 Months Ended
	Jun. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies, Policy	Commitments and Contingencies    In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2021
Accounting Policies [Abstract]
Schedule of Subsequent Events [Table Text Block]	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. On August 3, 2021, we acquired additional working interest in 12 wells that we currently operate and additional acreage in Webb County for total aggregate consideration of approximately $24 million. Through July 30, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2021: Oil Derivative Contracts Total Volumes (Bbls) (1) Weighted-Average Price 2021 Contracts 3Q21 30,000 $ 70.75 3Q21 (2) 12,000 $ 72.76 4Q21 81,250 $ 66.69 2022 Contracts 1Q22 45,000 $ 63.37 2Q22 45,500 $ 62.00 3Q22 46,000 $ 60.81 4Q22 46,000 $ 59.75 (1) Bbl refers to one barrel of oil. (2) Transaction for a swap purchase to reduce overall hedge position. Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 610,000 $ 4.00 4Q21 1,240,000 $ 3.90 2022 Contracts 2Q22 3,795,000 $ 2.99 3Q22 4,140,000 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2022 Contracts 4Q22 1,380,000 $ 2.90 $ 3.34 2023 Contracts 1Q23 1,350,000 $ 2.95 $ 3.51 2Q23 2,275,000 $ 2.40 $ 2.84 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 45,000 $ 26.32 2Q22 45,500 $ 26.32 3Q22 46,000 $ 26.32 4Q22 46,000 $ 26.32 There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Property and Equipment	The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): June 30, 2021 December 31, 2020 Property and Equipment Proved oil and gas properties $ 1,372,163 $ 1,310,008 Unproved oil and gas properties 24,312 28,090 Furniture, fixtures and other equipment 5,727 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (830,749) (801,279) Property and Equipment, Net $ 571,453 $ 542,094
Disaggregation of Revenue [Table Text Block]	The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended June 30, 2021 and 2020 and the six months ended June 30, 2021 and 2020 (in thousands): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Oil, natural gas and NGLs sales: Oil $ 15,890 $ 5,265 $ 33,356 $ 23,315 Natural gas 46,791 18,103 109,705 49,574 NGLs 7,180 1,478 13,541 5,333 Total $ 69,861 $ 24,846 $ 156,602 $ 78,222
Accounts Payable and Accrued Liabilities	The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): June 30, 2021 December 31, 2020 Trade accounts payable $ 8,736 $ 15,930 Accrued operating expenses 2,873 2,491 Accrued compensation costs 2,579 3,771 Asset retirement obligations – current portion 515 441 Accrued non-income based taxes 2,517 1,819 Accrued corporate and legal fees 143 150 Other payables 6,524 2,389 Total accounts payable and accrued liabilities $ 23,887 $ 26,991

Leases Leases (Tables)

Leases Leases (Tables)	6 Months Ended
	Jun. 30, 2021
Leases [Abstract]
Lease, Cost [Table Text Block]	Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property, plant and equipment acquisitions - short-term leases $ 1,491 $ 118 $ 1,820 $ 2,302 Property, plant and equipment acquisitions - operating leases — 5 — 10 Total lease costs in property, plant and equipment additions $ 1,491 $ 123 $ 1,820 $ 2,312 Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating expenses - short-term leases $ 618 $ 650 $ 1,085 $ 900 Lease operating expenses - operating leases 1,106 1,433 2,270 2,870 General and administrative, net - operating leases 178 179 351 359 Total lease cost expensed $ 1,902 $ 2,262 $ 3,706 $ 4,129
Lessee, Operating Lease, Disclosure [Table Text Block]	The lease term and the discount rate related to the Company's leases are as follows: June 30, 2021 Weighted-average remaining lease term (in years) 3.1 Weighted-average discount rate 4.1 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of June 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of June 30, 2021 2021 (Remaining) $ 3,462 2022 6,443 2023 5,642 2024 742 2025 742 Thereafter 856 Total undiscounted lease payments 17,887 Present value adjustment (1,188) Net operating lease liabilities $ 16,699
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental cash flow information related to leases was as follows (in thousands): Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Cash paid for amounts included in the measurement of lease liabilities; Operating cash flows from operating leases $ 2,618 $ 3,225 Investing cash flows from operating leases $ — $ 10

Share-Based Compensation (Table

Share-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2021
Share-based Payment Arrangement [Abstract]
Stock option activity	The following table provides information regarding stock option award activity for the six months ended June 30, 2021: Shares Wtd. Avg. Exer. Price Options outstanding, beginning of period 303,705 $ 27.73 Options forfeited (3,896) $ 16.96 Options expired (23,800) $ 23.25 Options outstanding, end of period 276,009 $ 28.12 Options exercisable, end of period 226,950 $ 28.53
Restricted stock activity	The following table provides information regarding RSU activity for the six months ended June 30, 2021: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 574,916 $ 9.02 RSUs granted 100,178 $ 8.33 RSUs forfeited (17,802) $ 11.09 RSUs vested (310,645) $ 9.02 RSUs outstanding, end of period 346,647 $ 8.71

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2021
Earnings Per Share [Abstract]
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS	The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended June 30, 2021 Three Months Ended June 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69) Dilutive Securities: RSU Awards — — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (19,951) 12,190 $ (1.64) $ (305,976) 11,910 $ (25.69) Six Months Ended June 30, 2021 Six Months Ended June 30, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 8,429 12,110 $ 0.70 $ (311,834) 11,868 $ (26.28) Dilutive Securities: RSU Awards 269 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 8,429 12,379 $ 0.68 $ (311,834) 11,868 $ (26.28)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2021
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consisted of the following (in thousands): June 30, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 198,000 $ 230,000 Second Lien Notes due 2024 200,000 200,000 398,000 430,000 Unamortized discount on Second Lien Notes due 2024 (1,157) (1,295) Unamortized debt issuance cost on Second Lien Notes due 2024 (3,397) (3,800) Long-Term Debt, net $ 393,446 $ 424,905 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our consolidated balance sheet. As of June 30, 2021 and December 31, 2020, we had $3.0 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Price-Risk Management Price-R_3

Price-Risk Management Price-Risk Management (Tables)	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2021: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 179,759 $ 51.19 4Q21 191,412 $ 53.60 2022 Contracts 1Q22 178,455 $ 45.77 2Q22 91,000 $ 54.00 3Q22 200,100 $ 47.05 4Q22 138,000 $ 53.20 2023 Contracts 1Q23 81,900 $ 55.70 Collar Contracts 2021 Contracts 3Q21 90,620 $ 34.34 $ 39.87 4Q21 84,640 $ 34.70 $ 41.01 2022 Contracts 1Q22 40,500 $ 40.00 $ 45.55 2Q22 115,850 $ 39.25 $ 46.20 2023 Contracts 2Q23 36,400 $ 56.00 $ 63.20 Natural Gas Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2021 Contracts 3Q21 330,000 $ 2.62 4Q21 290,000 $ 2.69 2022 Contracts 3Q22 2,100 $ 2.50 Collar Contracts 2021 Contracts 3Q21 8,185,175 $ 2.36 $ 2.82 4Q21 8,991,000 $ 2.61 $ 2.98 2022 Contracts 1Q22 8,465,000 $ 2.72 $ 3.36 2Q22 5,246,500 $ 2.15 $ 2.60 3Q22 4,899,000 $ 2.39 $ 2.72 4Q22 4,545,076 $ 2.41 $ 2.88 2023 Contracts 1Q23 4,297,000 $ 2.62 $ 3.11 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2021 Contracts 3Q21 10,120,000 $ (0.022) 4Q21 11,040,000 $ (0.013) 2022 Contracts 1Q22 6,300,000 $ 0.052 2Q22 2,730,000 $ (0.063) 3Q22 2,760,000 $ (0.063) 4Q22 2,760,000 $ (0.063) Oil Basis Swaps Total Volumes (Bbls) Weighted-Average Price 2021 Contracts 3Q21 262,200 $ 1.27 4Q21 241,500 $ 1.28 Calendar Monthly Roll Differential Swaps 2021 Contracts 3Q21 253,000 $ (0.34) 4Q21 241,500 $ (0.33) 2022 Contracts 1Q22 216,000 $ 0.09 2Q22 218,400 $ 0.09 3Q22 220,800 $ 0.09 4Q22 220,800 $ 0.09 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2021 Contracts 3Q21 192,324 $ 24.26 4Q21 192,324 $ 24.26 2022 Contracts 1Q22 45,000 $ 23.52

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2021
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2021 and December 31, 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in millions) Total Quoted Prices in Significant Other Significant June 30, 2021 Assets Natural Gas Basis Derivatives $ 0.3 $ — $ 0.3 $ — Oil Basis Derivatives 0.4 — 0.4 — Liabilities Natural Gas Derivatives 22.8 — 22.8 — Natural Gas Basis Derivatives 1.6 — 1.6 — Oil Derivatives 25.7 — 25.7 — Oil Basis Derivatives 1.0 — 1.0 — NGL Derivatives 4.5 — 4.5 — December 31, 2020 Assets Natural Gas Derivatives 1.5 — 1.5 — Natural Gas Basis Derivatives 1.1 — 1.1 — Oil Derivatives 2.5 — 2.5 — Liabilities Natural Gas Derivatives 4.0 — 4.0 — Natural Gas Basis Derivatives 0.4 — 0.4 — Oil Derivatives 5.9 — 5.9 — Oil Basis Derivatives 0.8 — 0.8 —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2021
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2020 and the six months ended June 30, 2021 (in thousands): Asset Retirement Obligations as of December 31, 2019 $ 4,447 Accretion expense 354 Liabilities incurred for new wells and facilities construction 281 Reductions due to plugged wells and facilities (103) Revisions in estimates (5) Asset Retirement Obligations as of December 31, 2020 $ 4,974 Accretion expense 148 Liabilities incurred for new wells and facilities construction 292 Reductions due to plugged wells and facilities (157) Revisions in estimates (156) Asset Retirement Obligations as of June 30, 2021 $ 5,101

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boe	Jun. 30, 2020USD ($)	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boe	Jun. 30, 2020USD ($)	Jul. 30, 2021MMBTUbbl$ / MMBTU$ / Boe	Dec. 31, 2020USD ($)
Property and Equipment
Proved oil and gas properties | $	$ 1,372,163		$ 1,372,163			$ 1,310,008
Unproved oil and gas properties | $	24,312		24,312			28,090
Furniture, fixtures, and other equipment | $	5,727		5,727			5,275
Less - Accumulated depreciation, depletion, and amortization | $	(830,749)		(830,749)			(801,279)
Net Furniture, Fixtures and other equipment | $	571,453		571,453			542,094
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	69,861	$ 24,846	156,602	$ 78,222
Accounts Payable and Accrued Liabilities
Trade accounts payable | $	8,736		8,736			15,930
Accrued operating expenses | $	2,873		2,873			2,491
Accrued compensation costs | $	2,579		2,579			3,771
Asset retirement obligation - current portion | $	515		515			441
Accrued non-income based taxes | $	2,517		2,517			1,819
Accrued corporate and legal fees | $	143		143			150
Other payables | $	6,524		6,524			2,389
Total Accounts payable and accrued liabilities | $	23,887		23,887			$ 26,991
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	15,890	5,265	33,356	23,315
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	46,791	18,103	109,705	49,574
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	$ 7,180	$ 1,478	$ 13,541	$ 5,333
Swap [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	179,759		179,759
Derivative, Swap Type, Fixed Price | $ / Boe	51.19		51.19
Swap [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					30,000
Derivative, Swap Type, Fixed Price | $ / Boe					70.75
Swap [Member] | Third Quarter 2021 [Member] | Swap Purchase | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					12,000
Derivative, Swap Type, Fixed Price | $ / Boe					72.76
Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	330,000		330,000
Derivative, Swap Type, Fixed Price	2.62		2.62
Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					610,000
Derivative, Swap Type, Fixed Price					4
Swap [Member] | Third Quarter 2021 [Member] | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	192,324		192,324
Derivative, Swap Type, Fixed Price	24.26		24.26
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	191,412		191,412
Derivative, Swap Type, Fixed Price | $ / Boe	53.60		53.60
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					81,250
Derivative, Swap Type, Fixed Price | $ / Boe					66.69
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	290,000		290,000
Derivative, Swap Type, Fixed Price	2.69		2.69
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					1,240,000
Derivative, Swap Type, Fixed Price					3.90
Swap [Member] | Fourth Quarter 2021 [Member] | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	192,324		192,324
Derivative, Swap Type, Fixed Price	24.26		24.26
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	178,455		178,455
Derivative, Swap Type, Fixed Price | $ / Boe	45.77		45.77
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					45,000
Derivative, Swap Type, Fixed Price | $ / Boe					63.37
Swap [Member] | First Quarter 2022 | NGL Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000		45,000
Derivative, Swap Type, Fixed Price	23.52		23.52
Swap [Member] | First Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					45,000
Derivative, Swap Type, Fixed Price					26.32
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	91,000		91,000
Derivative, Swap Type, Fixed Price | $ / Boe	54		54
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					45,500
Derivative, Swap Type, Fixed Price | $ / Boe					62
Swap [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					3,795,000
Derivative, Swap Type, Fixed Price					2.99
Swap [Member] | Second Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					45,500
Derivative, Swap Type, Fixed Price					26.32
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	200,100		200,100
Derivative, Swap Type, Fixed Price | $ / Boe	47.05		47.05
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					46,000
Derivative, Swap Type, Fixed Price | $ / Boe					60.81
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,100		2,100
Derivative, Swap Type, Fixed Price	2.50		2.50
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					4,140,000
Derivative, Swap Type, Fixed Price					3.02
Swap [Member] | Third Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					46,000
Derivative, Swap Type, Fixed Price					26.32
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	138,000		138,000
Derivative, Swap Type, Fixed Price | $ / Boe	53.20		53.20
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					46,000
Derivative, Swap Type, Fixed Price | $ / Boe					59.75
Swap [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,760,000
Derivative, Swap Type, Fixed Price					3.14
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl					46,000
Derivative, Swap Type, Fixed Price					26.32
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	81,900		81,900
Derivative, Swap Type, Fixed Price | $ / Boe	55.70		55.70
Collar Contracts [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	90,620		90,620
Derivative, Average Floor Price	34.34		34.34
Derivative, Average Cap Price	39.87		39.87
Collar Contracts [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,185,175		8,185,175
Derivative, Average Floor Price	2.36		2.36
Derivative, Average Cap Price	2.82		2.82
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	84,640		84,640
Derivative, Average Floor Price	34.70		34.70
Derivative, Average Cap Price	41.01		41.01
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,991,000		8,991,000
Derivative, Average Floor Price	2.61		2.61
Derivative, Average Cap Price	2.98		2.98
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	40,500		40,500
Derivative, Average Floor Price	40		40
Derivative, Average Cap Price	45.55		45.55
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,465,000		8,465,000
Derivative, Average Floor Price	2.72		2.72
Derivative, Average Cap Price	3.36		3.36
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	115,850		115,850
Derivative, Average Floor Price	39.25		39.25
Derivative, Average Cap Price	46.20		46.20
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,246,500		5,246,500
Derivative, Average Floor Price	2.15		2.15
Derivative, Average Cap Price	2.60		2.60
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,899,000		4,899,000
Derivative, Average Floor Price	2.39		2.39
Derivative, Average Cap Price	2.72		2.72
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,545,076		4,545,076
Derivative, Average Floor Price	2.41		2.41
Derivative, Average Cap Price	2.88		2.88
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					1,380,000
Derivative, Average Floor Price					2.90
Derivative, Average Cap Price					3.34
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,297,000		4,297,000
Derivative, Average Floor Price	2.62		2.62
Derivative, Average Cap Price	3.11		3.11
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					1,350,000
Derivative, Average Floor Price					2.95
Derivative, Average Cap Price					3.51
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	36,400		36,400
Derivative, Average Floor Price	56		56
Derivative, Average Cap Price	63.20		63.20
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU					2,275,000
Derivative, Average Floor Price					2.40
Derivative, Average Cap Price					2.84

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	Aug. 03, 2021USD ($)	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boeshares	Mar. 31, 2021shares	Jun. 30, 2020USD ($)shares	Mar. 31, 2020shares	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boeshares	Jun. 30, 2020USD ($)shares	Jul. 30, 2021MMBTUbbl$ / MMBTU$ / Boe	Dec. 31, 2020USD ($)
Summary of Significant Accounting Policies
Brent Spot Price		77	64			77
WTI Spot Price		74	59			74
Acquisition of oil and gas properties | $						$ 207	$ 3,394
Total capitalized internal costs | $		$ 1,200		$ 900		2,300	2,000
Proved oil and gas properties | $		1,372,163				1,372,163			$ 1,310,008
Unproved oil and gas properties | $		24,312				24,312			28,090
Furniture, fixtures, and other equipment | $		5,727				5,727			5,275
Less - Accumulated depreciation, depletion, and amortization | $		(830,749)				(830,749)			(801,279)
Net Furniture, Fixtures and other equipment | $		571,453				571,453			542,094
Write-down of oil and gas properties | $		0		260,342		0	355,948
Allowance for doubtful accounts receivable, current | $		100				100			100
Accounts receivable, gross | $		23,900				23,900			18,800
Accounts receivable related to joint interest owners | $		600				600			4,000
Severance tax receivable | $		1,000				1,000			2,400
Other receivables | $		400				$ 400			700
Percentage of working interest in wells						100.00%
Total amount of supervision fees charged to wells | $		1,200		900		$ 2,400	2,200
Provision (Benefit) for Income Taxes | $		0		22,420		0	21,179
Oil and gas sales | $		69,861		$ 24,846		156,602	$ 78,222
Trade accounts payable | $		8,736				8,736			15,930
Accrued operating expenses | $		2,873				2,873			2,491
Accrued payroll costs | $		2,579				2,579			3,771
Asset retirement obligation - current portion | $		515				515			441
Accrued non-income based taxes | $		2,517				2,517			1,819
Accrued corporate and legal fees | $		143				143			150
Other payables | $		6,524				6,524			2,389
Accounts payable and accrued liabilities | $		$ 23,887				$ 23,887			$ 26,991
Purchase of treasury stock (shares) | shares		13,969	60,177	1,098	26,675	74,146	27,773
Oil sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $		$ 15,890		$ 5,265		$ 33,356	$ 23,315
Natural gas sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $		46,791		18,103		109,705	49,574
NGL sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $		$ 7,180		$ 1,478		$ 13,541	$ 5,333
Subsequent Event [Member] | Webb County Acquisition
Summary of Significant Accounting Policies
Wells Purchased	12
Acquisition of oil and gas properties | $	$ 24,000
Swap [Member] | Third Quarter 2021 [Member] | Swap Purchase | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								12,000
Derivative, Swap Type, Fixed Price | $ / Boe								72.76
Swap [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		179,759				179,759
Derivative, Swap Type, Fixed Price | $ / Boe		51.19				51.19
Swap [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								30,000
Derivative, Swap Type, Fixed Price | $ / Boe								70.75
Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		330,000				330,000
Derivative, Swap Type, Fixed Price		2.62				2.62
Swap [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								610,000
Derivative, Swap Type, Fixed Price								4
Swap [Member] | Third Quarter 2021 [Member] | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		192,324				192,324
Derivative, Swap Type, Fixed Price		24.26				24.26
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		191,412				191,412
Derivative, Swap Type, Fixed Price | $ / Boe		53.60				53.60
Swap [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								81,250
Derivative, Swap Type, Fixed Price | $ / Boe								66.69
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		290,000				290,000
Derivative, Swap Type, Fixed Price		2.69				2.69
Swap [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								1,240,000
Derivative, Swap Type, Fixed Price								3.90
Swap [Member] | Fourth Quarter 2021 [Member] | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		192,324				192,324
Derivative, Swap Type, Fixed Price		24.26				24.26
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		178,455				178,455
Derivative, Swap Type, Fixed Price | $ / Boe		45.77				45.77
Swap [Member] | First Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								45,000
Derivative, Swap Type, Fixed Price | $ / Boe								63.37
Swap [Member] | First Quarter 2022 | NGL Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		45,000				45,000
Derivative, Swap Type, Fixed Price		23.52				23.52
Swap [Member] | First Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								45,000
Derivative, Swap Type, Fixed Price								26.32
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		91,000				91,000
Derivative, Swap Type, Fixed Price | $ / Boe		54				54
Swap [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								45,500
Derivative, Swap Type, Fixed Price | $ / Boe								62
Swap [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								3,795,000
Derivative, Swap Type, Fixed Price								2.99
Swap [Member] | Second Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								45,500
Derivative, Swap Type, Fixed Price								26.32
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		200,100				200,100
Derivative, Swap Type, Fixed Price | $ / Boe		47.05				47.05
Swap [Member] | Third Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								46,000
Derivative, Swap Type, Fixed Price | $ / Boe								60.81
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		2,100				2,100
Derivative, Swap Type, Fixed Price		2.50				2.50
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								4,140,000
Derivative, Swap Type, Fixed Price								3.02
Swap [Member] | Third Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								46,000
Derivative, Swap Type, Fixed Price								26.32
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		138,000				138,000
Derivative, Swap Type, Fixed Price | $ / Boe		53.20				53.20
Swap [Member] | Fourth Quarter 2022 | Oil Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								46,000
Derivative, Swap Type, Fixed Price | $ / Boe								59.75
Swap [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								2,760,000
Derivative, Swap Type, Fixed Price								3.14
Swap [Member] | Fourth Quarter 2022 | NGL Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl								46,000
Derivative, Swap Type, Fixed Price								26.32
Swap [Member] | First Quarter 2023 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl		81,900				81,900
Derivative, Swap Type, Fixed Price | $ / Boe		55.70				55.70
Collar Contracts [Member] | Third Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		90,620				90,620
Derivative, Average Floor Price		34.34				34.34
Derivative, Average Cap Price		39.87				39.87
Collar Contracts [Member] | Third Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		8,185,175				8,185,175
Derivative, Average Floor Price		2.36				2.36
Derivative, Average Cap Price		2.82				2.82
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		84,640				84,640
Derivative, Average Floor Price		34.70				34.70
Derivative, Average Cap Price		41.01				41.01
Collar Contracts [Member] | Fourth Quarter 2021 [Member] | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		8,991,000				8,991,000
Derivative, Average Floor Price		2.61				2.61
Derivative, Average Cap Price		2.98				2.98
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		40,500				40,500
Derivative, Average Floor Price		40				40
Derivative, Average Cap Price		45.55				45.55
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		8,465,000				8,465,000
Derivative, Average Floor Price		2.72				2.72
Derivative, Average Cap Price		3.36				3.36
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		115,850				115,850
Derivative, Average Floor Price		39.25				39.25
Derivative, Average Cap Price		46.20				46.20
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		5,246,500				5,246,500
Derivative, Average Floor Price		2.15				2.15
Derivative, Average Cap Price		2.60				2.60
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		4,899,000				4,899,000
Derivative, Average Floor Price		2.39				2.39
Derivative, Average Cap Price		2.72				2.72
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		4,545,076				4,545,076
Derivative, Average Floor Price		2.41				2.41
Derivative, Average Cap Price		2.88				2.88
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								1,380,000
Derivative, Average Floor Price								2.90
Derivative, Average Cap Price								3.34
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		4,297,000				4,297,000
Derivative, Average Floor Price		2.62				2.62
Derivative, Average Cap Price		3.11				3.11
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								1,350,000
Derivative, Average Floor Price								2.95
Derivative, Average Cap Price								3.51
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU		36,400				36,400
Derivative, Average Floor Price		56				56
Derivative, Average Cap Price		63.20				63.20
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU								2,275,000
Derivative, Average Floor Price								2.40
Derivative, Average Cap Price								2.84
Minimum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property						2 years
Maximum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property						20 years

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 1,902	$ 2,262	$ 3,706	$ 4,129
Operating Lease, Weighted Average Remaining Lease Term	3 years 1 month 6 days		3 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent	4.10%		4.10%
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 3,462		$ 3,462
Lessee, Operating Lease, Liability, Payments, Due Year Two	6,443		6,443
Lessee, Operating Lease, Liability, Payments, Due Year Three	5,642		5,642
Lessee, Operating Lease, Liability, Payments, Due Year Four	742		742
Lessee, Operating Lease, Liability, Payments, Due Year Five	742		742
Lessee, Operating Lease, Liability, Payments, Due after Year Five	856		856
Lessee, Operating Lease, Liability, Payments, Due	17,887		17,887
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(1,188)		(1,188)
Operating Lease, Liability	16,699		16,699
Operating Lease, Payments			2,618	3,225
Operating Lease, Payments, Use			0	10
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	618	650	1,085	900
Operating Lease, Cost	1,106	1,433	2,270	2,870
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	178	179	351	359
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	1,491	118	1,820	2,302
Operating Lease, Cost	0	5	0	10
Lease, Cost	$ 1,491	$ 123	$ 1,820	$ 2,312

Share-Based Compensation (Detai

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Jun. 30, 2021	Feb. 24, 2021	May 21, 2019	Feb. 20, 2018	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Share-based Compensation (Details Textual)
Stock-based compensation expenses							$ 2,260	$ 2,437
Share-based compensation (capitalized)					$ 100	$ 100	100	100
Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 400				400		400
Stock option award outstanding aggregate intrinsic value	$ 100				$ 100		100
Remaining contract life of outstanding stock options.	4 years 7 months 6 days
Remaining contract life of exercisable stock option	4 years 4 months 24 days
Stock option award exercisable aggregate intrinsic value							$ 100
Stock Option Activity
Options outstanding, beginning of period, shares	276,009				276,009		276,009		303,705
Options outstanding, beginning of period, weighted average price	$ 28.12				$ 28.12		$ 28.12		$ 27.73
Options Forfeitures in Period							(3,896)
Options forfeited, weighted average price							$ 16.96
Options expired, shares							(23,800)
Options expired, weighted average price							$ 23.25
Options exercisable, end of period, shares	226,950				226,950		226,950
Options exercisable, end of period, weighted average price	$ 28.53				$ 28.53		$ 28.53
Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 1,900				$ 1,900		$ 1,900
Unrecognized compensation expense weighted-average period							1 year
Restricted stock activity
Restricted shares outstanding, beginning of period, shares							574,916
Restricted shares outstanding, beginning of period, weighted average price							$ 9.02
Restricted shares granted, shares							100,178
Restricted shares granted, weighted average price							$ 8.33
Restricted shares forfeited, weighted average price							(17,802)
Restricted shares forfeited, weighted average price							$ 11.09
Restricted shares vested, shares							(310,645)
Restricted shares vested, weighted average price							$ 9.02
Restricted shares outstanding, end of period, shares	346,647				346,647		346,647
Restricted shares outstanding, end of period, weighted average price	$ 8.71				$ 8.71		$ 8.71
Performance-based stock unit [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 2,200				$ 2,200		$ 2,200
Unrecognized compensation expense weighted-average period	1 year 3 months 18 days
Restricted stock activity
Restricted shares granted, shares		161,389	99,500	30,700
Restricted shares granted, weighted average price		$ 13.13	$ 18.86	$ 41.66
Restricted shares vested, shares							(23,800)
Restricted shares outstanding, end of period, shares	83,600				83,600		83,600
Percent of payout for performance based stock units	100.00%	157.60%	112.90%	150.61%	100.00%		100.00%
Minimum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period							1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term							1 year
Minimum [Member] | Performance-based stock unit [Member]
Restricted stock activity
Percent of payout for performance based stock units		0.00%	0.00%	0.00%
Maximum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period							5 years
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term							5 years
Maximum [Member] | Performance-based stock unit [Member]
Share-based Compensation (Details Textual)
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term		2 years	3 years	3 years
Restricted stock activity
Percent of payout for performance based stock units		200.00%	200.00%	200.00%
General and Administrative Expense [Member]
Share-based Compensation (Details Textual)
Stock-based compensation expenses					$ 1,200	$ 1,200	$ 2,300	$ 2,400

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2021	Jun. 30, 2020
Basic EPS:
Net Income (Loss)	$ (19,951)	$ 28,380	$ (305,976)	$ (5,858)	$ 8,429	$ (311,834)
Income, share amounts	12,190		11,910		12,110	11,868
Earnings Per Share, Basic	$ (1.64)		$ (25.69)		$ 0.70	$ (26.28)
Dilutive Securities:
Dilutive RSUs	0		0		269	0
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ (19,951)		$ (305,976)		$ 8,429	$ (311,834)
Weighted Average Number of Shares Outstanding, Diluted	12,190		11,910		12,379	11,868
Earnings Per Share, Diluted	$ (1.64)		$ (25.69)		$ 0.68	$ (26.28)
Stock Options [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	300		300		300	300
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	100		200		100	200
Performance Shares [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	0		100		100	100

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Apr. 16, 2021USD ($)	Nov. 02, 2020USD ($)	Dec. 15, 2017USD ($)	Jun. 30, 2021USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2021USD ($)	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities				$ 393,446		$ 393,446		$ 424,905
Gross interest expense including amortization of debt issuance costs				7,436	$ 8,026	14,454	$ 16,433
Capitalized interest on our unproved properties				0	0	0	0
Payments of Debt Issuance Costs						2,400	0
Write off of Debt Issuance Cost						229	459
Second Lien [Abstract]
Long-term debt, gross				398,000		398,000		430,000
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net				3,000		3,000		1,400
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net				3,397		3,397		3,800
Long-term Debt, excluding current maturities			$ 198,000	200,000		200,000		200,000
Gross interest expense including amortization of debt issuance costs				4,600	4,600	9,200	9,500
Second Lien [Abstract]
Long-term debt, gross			200,000
Debt Instrument, Unamortized Discount			(2,000)	(1,157)		(1,157)		(1,295)
Additional notes issuable			$ 100,000
Additional interest in the event of default			0.020
Make whole premium during year 4			0.010
Second Lien, Required Security Interest on Proved Reserves			85.00%
Second Lien, Required Security Interest on Oil and Gas Properties			85.00%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%			9.00%
Second Lien, Asset Coverage Ratio, Minimum			1.25
Discount Rate for Estimated Future Net Revenues from Proved Properties			10.00%
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum			4.5
Long-term debt, net				195,400		195,400
Second Lien Notes [Member] | London Interbank Offered Rate (LIBOR) [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate			0.075
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate			0.065
Line of Credit [Member] | New Credit Facility [Member]
Bank Borrowings
Long-term Debt, excluding current maturities				198,000		198,000		$ 230,000
Line of Credit Facility, Current Borrowing Capacity	$ 300,000	$ 310,000
Line of Credit, Basis Point Increase	50
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before December 31, 2020		3.50
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before December 31, 2021	3.25
Line of Credit, Covenant, Debt to EBITDA Ratio, On or Before March 31, 2022	3
Line of Credit, Minimum Rolling Hedge Requirement	0.50
Line of Credit, Required Security Interest on Oil and Gas Properties	90.00%	85.00%
Line of Credit Facility, Maximum Borrowing Capacity	$ 600,000
Line of Credit, Letters of Credit Issuable	$ 25,000
Commitment fee basis points for the credit facility	0.50%
Line of Credit, Additional Interest Due to Payment Default	2.00%
Line of Credit, Covenant, Current Ratio, Minimum	1
Gross interest expense including amortization of debt issuance costs				2,800	$ 3,500	5,300	$ 6,900
Payments of Debt Issuance Costs				$ 2,400
Write off of Debt Issuance Cost						$ 200
Line of Credit [Member] | New Credit Facility [Member] | Minimum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0225
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0325
Line of Credit [Member] | New Credit Facility [Member] | Maximum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0325
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0425

Acquisitions and Dispositions_2

Acquisitions and Dispositions Acquisitions and Dispositions (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 22, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments for (Proceeds from) Other Investing Activities	$ 1,084	$ 426
Bay De Chene [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase and sale contract			$ 16,300
Payments for (Proceeds from) Other Investing Activities	1,100	$ 400
Cash to be released for purchase and sale contract	$ 500

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boe	Jun. 30, 2020USD ($)	Jun. 30, 2021USD ($)MMBTUbbl$ / MMBTU$ / Boe	Jun. 30, 2020USD ($)	Dec. 31, 2020USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (46,100)	$ (8,500)	$ (64,300)	$ 79,800
Cash Received (Paid) On Settlements of Derivative Contracts | $			(10,708)	67,496
Cash Received (Paid) On Monetized Derivative Contracts | $				$ 38,300
Receivables for Settled Derivatives | $	400		400		$ 800
Payables for Settled Derivatives | $	5,100		5,100		800
Derivative, Fair Value, Net | $	(54,900)		(54,900)		(6,000)
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	700		700		4,800
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	100		100		300
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	45,400		45,400		8,200
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 10,300		$ 10,300		$ 2,900
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	179,759		179,759
Derivative, Swap Type, Fixed Price | $ / Boe	51.19		51.19
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	191,412		191,412
Derivative, Swap Type, Fixed Price | $ / Boe	53.60		53.60
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	178,455		178,455
Derivative, Swap Type, Fixed Price | $ / Boe	45.77		45.77
Swap [Member] | Oil Derivative Swaps [Member] | Second Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	91,000		91,000
Derivative, Swap Type, Fixed Price | $ / Boe	54		54
Swap [Member] | Oil Derivative Swaps [Member] | Third Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	200,100		200,100
Derivative, Swap Type, Fixed Price | $ / Boe	47.05		47.05
Swap [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	138,000		138,000
Derivative, Swap Type, Fixed Price | $ / Boe	53.20		53.20
Swap [Member] | Oil Derivative Swaps [Member] | First Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	81,900		81,900
Derivative, Swap Type, Fixed Price | $ / Boe	55.70		55.70
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	330,000		330,000
Derivative, Swap Type, Fixed Price	2.62		2.62
Swap [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	290,000		290,000
Derivative, Swap Type, Fixed Price	2.69		2.69
Swap [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,100		2,100
Derivative, Swap Type, Fixed Price	2.50		2.50
Swap [Member] | NGL Derivative | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	192,324		192,324
Derivative, Swap Type, Fixed Price	24.26		24.26
Swap [Member] | NGL Derivative | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	192,324		192,324
Derivative, Swap Type, Fixed Price	24.26		24.26
Swap [Member] | NGL Derivative | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000		45,000
Derivative, Swap Type, Fixed Price	23.52		23.52
Collar Contracts [Member] | Oil Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	90,620		90,620
Derivative, Average Floor Price	34.34		34.34
Derivative, Average Cap Price	39.87		39.87
Collar Contracts [Member] | Oil Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	84,640		84,640
Derivative, Average Floor Price	34.70		34.70
Derivative, Average Cap Price	41.01		41.01
Collar Contracts [Member] | Oil Derivative Swaps [Member] | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	40,500		40,500
Derivative, Average Floor Price	40		40
Derivative, Average Cap Price	45.55		45.55
Collar Contracts [Member] | Oil Derivative Swaps [Member] | Second Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	115,850		115,850
Derivative, Average Floor Price	39.25		39.25
Derivative, Average Cap Price	46.20		46.20
Collar Contracts [Member] | Oil Derivative Swaps [Member] | Second Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	36,400		36,400
Derivative, Average Floor Price	56		56
Derivative, Average Cap Price	63.20		63.20
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,185,175		8,185,175
Derivative, Average Floor Price	2.36		2.36
Derivative, Average Cap Price	2.82		2.82
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,991,000		8,991,000
Derivative, Average Floor Price	2.61		2.61
Derivative, Average Cap Price	2.98		2.98
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,465,000		8,465,000
Derivative, Average Floor Price	2.72		2.72
Derivative, Average Cap Price	3.36		3.36
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | Second Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,246,500		5,246,500
Derivative, Average Floor Price	2.15		2.15
Derivative, Average Cap Price	2.60		2.60
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | Third Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,899,000		4,899,000
Derivative, Average Floor Price	2.39		2.39
Derivative, Average Cap Price	2.72		2.72
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | Fourth Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,545,076		4,545,076
Derivative, Average Floor Price	2.41		2.41
Derivative, Average Cap Price	2.88		2.88
Collar Contracts [Member] | Natural Gas Derivative Swaps [Member] | First Quarter 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,297,000		4,297,000
Derivative, Average Floor Price	2.62		2.62
Derivative, Average Cap Price	3.11		3.11
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,120,000		10,120,000
Derivative, Swap Type, Fixed Price	(0.022)		(0.022)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,040,000		11,040,000
Derivative, Swap Type, Fixed Price	(0.013)		(0.013)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,300,000		6,300,000
Derivative, Swap Type, Fixed Price	0.052		0.052
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,730,000		2,730,000
Derivative, Swap Type, Fixed Price	(0.063)		(0.063)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,760,000		2,760,000
Derivative, Swap Type, Fixed Price	(0.063)		(0.063)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,760,000		2,760,000
Derivative, Swap Type, Fixed Price	(0.063)		(0.063)
Basis Swap [Member] | Oil Basis Derivative [Member] | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	262,200		262,200
Derivative, Swap Type, Fixed Price	1.27		1.27
Basis Swap [Member] | Oil Basis Derivative [Member] | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	241,500		241,500
Derivative, Swap Type, Fixed Price	1.28		1.28
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	253,000		253,000
Derivative, Swap Type, Fixed Price	(0.34)		(0.34)
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2021 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	241,500		241,500
Derivative, Swap Type, Fixed Price	(0.33)		(0.33)
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	216,000		216,000
Derivative, Swap Type, Fixed Price	0.09		0.09
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	218,400		218,400
Derivative, Swap Type, Fixed Price	0.09		0.09
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	220,800		220,800
Derivative, Swap Type, Fixed Price	0.09		0.09
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	220,800		220,800
Derivative, Swap Type, Fixed Price	0.09		0.09

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		$ 1.5
Derivative Liability	$ 22.8	4
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.3	1.1
Derivative Liability	1.6	0.4
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		2.5
Derivative Liability	25.7	5.9
Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.4
Derivative Liability	1	0.8
NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	4.5
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		1.5
Derivative Liability	22.8	4
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.3	1.1
Derivative Liability	1.6	0.4
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		2.5
Derivative Liability	25.7	5.9
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0.4
Derivative Liability	1	0.8
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	4.5
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset		0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0
Derivative Liability	0	$ 0
Fair Value, Inputs, Level 3 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability	$ 0

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 5,101		$ 5,101		$ 4,974	$ 4,447
Accretion expense	74	$ 88	148	$ 173	354
Liabilities incurred for new wells and facilities construction			292		281
Reductions due to plugged wells and facilities			(157)		(103)
Revisions in estimates			(156)		(5)
Asset retirement obligation - current portion	$ 515		$ 515		$ 441