SilverBow Resources (SBOW) 10-K 3 Mar 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2021	Jan. 31, 2022	Jun. 30, 2021
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Public Float			$ 108,089,448
Entity Common Stock, Shares Outstanding		16,631,175
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Filer Category	Accelerated Filer
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Document Annual Report	true

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor [Line Items]
Auditor Name	BDO USA, LLP
Auditor Firm ID	243
Auditor Location	Houston, Texas
ICFR Auditor Attestation Flag	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 1,121	$ 2,118
Accounts receivable	49,777	25,850
Fair value of commodity derivatives	2,806	4,821
Other current assets	1,875	2,184
Total Current Assets	55,579	34,973
Property and Equipment:
Property, Plant and Equipment, Gross	1,611,953	1,343,373
Less - Accumulated depreciation, depletion, and amortization	(869,985)	(801,279)
Property, Plant and Equipment, Net	741,968	542,094
Right of use assets	16,065	4,366
Fair value of long-term commodity derivatives	201	281
Other Long-Term Assets	5,641	1,421
Total Assets	819,454	583,135
Current Liabilities:
Accounts payable and accrued liabilities	35,034	26,991
Fair value of commodity derivatives	47,453	8,171
Accrued capital costs	7,354	7,324
Accrued interest	697	983
Current lease liability	7,222	3,473
Undistributed oil and gas revenues	23,577	11,098
Total Current Liabilities	121,337	58,040
Long-Term Debt	372,825	424,905
Non-current lease liability	9,090	951
Deferred tax liabilities, net	6,516	303
Asset Retirement Obligation	5,526	4,533
Fair value of long-term commodity derivatives	8,585	2,946
Other long-term liabilities	3,043	424
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common Stock, Value, Issued	168	121
Additional paid-in capital	$ 413,017	$ 297,712
Treasury Stock, Shares	191,670	117,084
Treasury Stock, Value	$ (2,984)	$ (2,372)
Retained earnings (Accumulated deficit)	(117,669)	(204,428)
Total Stockholders' Equity (Deficit)	292,532	91,033
Total Liabilities and Stockholders' Equity	819,454	583,135
Capitalized Costs, Unproved Properties	$ 17,090	$ 28,090
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares, Issued	16,822,845	12,053,763
Common Stock, Shares, Outstanding	16,631,175	11,936,679

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) $ in Thousands	Dec. 31, 2020USD ($)$ / sharesshares
Statement of Financial Position [Abstract]
Capitalized Costs, Unproved Properties | $	$ 28,090
Preferred stock, par value (in dollars per share) | $ / shares	$ 0.01
Preferred stock, shares authorized	10,000,000
Preferred stock, shares outstanding	0
Common Stock, Par or Stated Value Per Share | $ / shares	$ 0.01
Common Stock, Shares Authorized	40,000,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Oil and gas sales	$ 407,200	$ 177,386
Costs and Expenses:
General and administrative, net	21,799	22,608
Depreciation, depletion, and amortization	68,629	64,564
Accretion of asset retirement obligation	306	354
Lease operating cost	27,206	21,360
Workovers	514	8
Results of Operations, Transportation Costs	24,145	20,649
Severance and other taxes	19,307	10,514
Write-down of oil and gas properties	0	355,948
Total Operating Expenses	161,906	496,005
Operating Income (Loss)	245,294	(318,619)
Net gain (loss) on commodity derivatives	(123,018)	61,304
Interest expense, net	(29,129)	(31,228)
Other income (expense), net	10	72
Income (Loss) Before Income Taxes	93,157	(288,471)
Provision (Benefit) for Income Taxes	6,398	20,911
Net Income (Loss)	$ 86,759	$ (309,382)
Per Share Amounts-
Earnings (Loss) Per Share, Basic	$ 6.61	$ (25.99)
Earnings (Loss) Per Share, Diluted	$ 6.42	$ (25.99)
Weighted Average Shares Outstanding - Basic	13,118	11,902
Weighted Average Shares Outstanding - Diluted	13,520	11,902

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Deficit)
Beginning Balance	$ 395,707	$ 119	$ 292,916	$ (2,282)	$ 104,954
Shares issued from option exercise	0	0	0	0	0
Purchase of treasury shares	(90)	0	0	(90)	0
Issuance of restricted stock	1	2	(1)	0	0
Amortization of share-based compensation	4,797	0	4,797	0	0
Net Income (Loss)	$ (309,382)	0	0	0	(309,382)
Shares issued from stock option exercises	5
Treasury Stock, Shares, Acquired	28,731
Vesting of share-based compensation	158,726
Beginning Balance	$ 91,033	121	297,712	(2,372)	(204,428)
Shares issued from option exercise	0	0	0	0	0
Purchase of treasury shares	(612)	0	0	(612)	0
Issuance of restricted stock	0	3	(3)	0	0
Stock Issued During Period, Value, New Issues	26,956	12	26,944	0	0
Stock Issued During Period, Value, Acquisitions	83,522	32	83,490	0	0
Amortization of share-based compensation	4,874	0	4,874	0	0
Net Income (Loss)	$ 86,759	0	0	0	86,759
Shares issued from stock option exercises	0
Treasury Stock, Shares, Acquired	74,586
Vesting of share-based compensation	336,247
Issuance of common stock	1,222,209
Issuance pursuant to acquisitions	3,210,626
Beginning Balance	$ 292,532	$ 168	$ 413,017	$ (2,984)	$ (117,669)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Operating Activities:
Net Income (Loss)	$ 86,759	$ (309,382)
Adjustments to reconcile net income to net cash provided by operation activities -
Write-down of oil and gas properties	0	355,948
Depreciation, depletion, and amortization	68,629	64,564
Accretion of asset retirement obligation	306	354
Deferred income taxes	6,212	21,390
Stock-based compensation expense	4,645	4,557
Gain (Loss) on Sale of Derivatives	123,018	(61,304)
Cash Received (Paid) On Settlements of Derivative Contracts	(70,582)	78,421
Asset Retirement Obligation, Cash Paid to Settle	(158)	(94)
Write off of Deferred Debt Issuance Cost	229	557
Other Noncash Income (Expense)	2,877	3,061
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other assets	(23,513)	9,011
Increase (decrease) in accounts payable and accrued liabilities	17,507	(977)
Increase (decrease) in income taxes payable	(83)	480
Increase (decrease) in accrued interest	(286)	(414)
Net Cash Provided by Operating Activities	215,726	165,212
Cash Flows from Investing Activities:
Additions to property and equipment	(133,638)	(114,738)
Acquisition of properties	(51,734)	(4,544)
Proceeds from Sale of Property, Plant, and Equipment	0	(4,777)
Payments for (Proceeds from) Other Investing Activities	(1,084)	(826)
Net Cash Used in Investing Activities	(186,456)	(115,331)
Cash Flows from Financing Activities:
Payments of long-term debt	(50,000)	0
Proceeds from bank borrowings	335,000	107,000
Payments of bank borrowings	(338,000)	(156,000)
Proceeds from Issuance or Sale of Equity	26,956	0
Purchase of treasury shares	(612)	(90)
Payments of debt issuance costs	(3,611)	(31)
Net Cash Provided by (Used in) Financing Activities	(30,267)	(49,121)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	(997)	760
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	1,121	2,118
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	27,221	28,929
Increase (decrease) in accrued payables for capital	(4,033)	(19,365)
Other Significant Noncash Transaction, Value of Consideration Given	$ (83,522)	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation . The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”, “we”, “our” or “us”) 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 and Austin Chalk 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 consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of oil and natural gas. 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 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, and thereafter increased to approximately $77 and $75 per barrel, respectively, on December 31, 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. 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. Through February 25, 2022, 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 December 31, 2021: Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Swap Contracts 2022 Contracts 4Q22 23,000 $ 80.82 2023 Contracts 1Q23 45,000 $ 78.60 2Q23 45,500 $ 76.90 3Q23 46,000 $ 75.45 4Q23 94,300 $ 73.52 Natural Gas Derivative Contracts Total Volumes Weighted Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2Q22 600,000 $ 4.50 3Q22 310,000 $ 4.57 Collar Contracts 2022 Contracts 1Q22 310,000 $ 5.00 $ 7.40 3Q22 920,000 $ 4.40 $ 5.02 4Q22 920,000 $ 4.40 $ 5.43 2023 Contracts 1Q23 900,000 $ 4.40 $ 5.84 4Q23 4,462,000 $ 3.25 $ 3.92 2024 Contracts 1Q24 910,000 $ 3.25 $ 5.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 15,500 $ 35.40 2Q22 45,500 $ 35.40 3Q22 46,000 $ 35.40 4Q22 46,000 $ 35.40 Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 2Q22 45,500 $ 2.63 Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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 flow therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness 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 used in the assessment of business combinations and asset purchases, • 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 may 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 years ended December 31, 2021 and 2020, such internal costs when capitalized totaled $4.8 million and $3.5 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2021 and 2020. The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,588,978 $ 1,310,008 Unproved oil and gas properties 17,090 28,090 Furniture, fixtures, and other equipment 5,885 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (869,985) (801,279) Property and Equipment, Net $ 741,968 $ 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 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. The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are not a business combination. A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions. Full-Cost Ceiling Test . At the end of the 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. There was no ceiling test write-down for the year ended December 31, 2021. Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the year ended December 31, 2020. 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 flow 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. 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 Consolidated Statements of Operations for years ended December 31, 2021 and 2020 (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Oil, natural gas and NGLs sales: Oil $ 98,607 $ 57,651 Natural gas 267,687 105,234 NGLs 40,906 14,500 Total $ 407,200 $ 177,386 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 December 31, 2021 and 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 consolidated balance sheets. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million due from joint interest owners, $1.0 million for severance tax credit receivables and $1.5 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 for 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 consolidated statements of operations. The amount of supervision fees charged for each of the years ended December 31, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $5.1 million and $4.4 million for the years ended December 31, 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. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 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. 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, 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 deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter of 2020 to offset its net deferred tax assets in excess of deferred tax liabilities. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of December 31, 2021. We recorded an income tax provision of $6.4 million which was primarily attributable to deferred federal income tax expense for the year ended December 31, 2021. 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 has examined the impact of the CARES Act and has concluded the CARES Act will not have a material effect on its financial condition, results of operation, or liquidity. Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 9,688 $ 15,930 Accrued operating expenses 4,192 2,491 Accrued compensation costs 7,029 3,771 Asset retirement obligations – current portion 524 441 Accrued non-income based taxes 3,314 1,819 Accrued corporate and legal fees 1,972 150 Other payables (1) 8,315 2,389 Total accounts payable and accrued liabilities $ 35,034 $ 26,991 (1) Included in Other Payables is $6.4 million and $0.8 million in payables for settled derivatives for the years ended December 31, 2021 and 2020, respectively. 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. Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss. For the years ended December 31, 2021 and 2020, parties that accounted for 10% or more of our total oil and gas receipts were as follows: Purchasers greater than 10% Year Ended December 31, 2021 Year Ended December 31, 2020 Kinder Morgan 26 % 19 % Plains Marketing 10 % 17 % Twin Eagle 15 % 17 % Trafigura US 16 % 13 % Shell Trading 12 % * *Oil and gas receipts less than 10% Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2021 and 2020, we purchased 74,586 and 28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. New Accounting Pronouncements . In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements. In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures. In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures. ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company may sell, from time to time in the open market, shares of the Company’s common stock, having aggregate proceeds of up to $40.0 million (the “ATM Program”). The Company intends to use the net proceeds from any sales through the ATM Program for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment or refinancing of outstanding debt, financing acquisitions or investments, financing other business opportunities, and general working capital purposes. During the year ended December 31, 2021 (from August 13, 2021 through December 31, 2021), the Company sold 1,222,209 shares of common stock for net proceeds of $27.0 million after deducting sales agents' commissions and other related expenses.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Earnings Per Share	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 restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units 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. 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): Year Ended December 31, 2021 Year Ended December 31, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 86,759 13,118 $ 6.61 $ (309,382) 11,902 $ (25.99) Dilutive Securities: Restricted Stock Unit Awards 285 — Performance Based Stock Unit Awards 117 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 86,759 13,520 $ 6.42 $ (309,382) 11,902 $ (25.99) Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the years ended December 31, 2021 and 2020, because these stock options were antidilutive. There were no antidilutive shares of restricted stock units for the year ended December 31, 2021. Approximately 0.2 million shares of restricted stock units that could be converted to common shares were not included in the computation of Diluted EPS for the year ended December 31, 2020 because they were antidilutive.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Provision (Benefit) for Income Taxes	Provision (Benefit) for Income Taxes Income (Loss) before taxes is as follows (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Income (Loss) Before Income Taxes $ 93,157 $ (288,471) The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Current $ 186 $ (480) Deferred 6,212 21,391 Total $ 6,398 $ 20,911 Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows: Year Ended December 31, 2021 Year Ended December 31, 2020 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 1.0 % 0.6 % Executive compensation limitation 0.6 % — % Other, net 0.6 % (0.2) % Valuation allowance adjustments (16.2) % (28.6) % Effective rate 6.9 % (7.2) % The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2021 and 2020 were as follows (in thousands): December 31, 2021 December 31, 2020 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 97,142 $ 93,293 Other carryover items 642 610 Asset retirement obligations 1,306 1,074 Share-based compensation 579 959 Lease liability 3,425 929 Derivative contracts 11,451 — Other 2,111 1,029 Valuation allowance (67,578) (82,618) Total deferred tax assets $ 49,078 $ 15,276 Deferred tax liabilities: Oil and gas exploration and development costs $ (52,219) $ (13,008) Derivative contracts — (1,653) Leased assets (3,374) (917) Other (1) (1) Total deferred tax liabilities (55,594) (15,579) Net deferred tax asset (liabilities) $ (6,516) $ (303) State net deferred tax liabilities $ (1,016) $ (303) Federal net deferred tax liabilities (5,500) — Net deferred tax asset (liabilities) $ (6,516) $ (303) The Company’s valuation allowance balance was $67.6 million and $82.6 million at December 31, 2021 and 2020, respectively. The Company recorded a net deferred tax liability for state income tax purposes at December 31, 2021 and 2020. The Company’s NOL carryforward asset is attributable to Federal tax losses of $114.6 million generated from 2013 through 2015, $159.6 million generated in 2017 and $188.3 million generated from 2018 through 2021. The losses generated between 2013 and 2015 are subject to an annual utilization limit under Sec. 382. These losses will expire between 2033 and 2035 if not utilized. The 2017 loss will expire in 2037 if not utilized. The losses generated from 2018 through 2021 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. Our U.S. federal and most state income tax returns from 2018 forward are subject to examination. For years prior to 2018 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2017 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company's long-term debt consisted of the following (in thousands): December 31, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 227,000 $ 230,000 Second Lien Notes due 2026 150,000 200,000 377,000 430,000 Unamortized discount on Second Lien Notes (1,061) (1,295) Unamortized debt issuance cost on Second Lien Notes (3,114) (3,800) Total Long-Term Debt $ 372,825 $ 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 December 31, 2021 and 2020, we had $3.6 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 $227.0 million and $230.0 million as of December 31, 2021 and 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 Eighth Amendment to the Credit Facility, effective November 12, 2021 (the “Eighth Amendment”), which increased the borrowing base under the Credit Facility to $460.0 million (from $300.0 million). The Credit Facility matures April 19, 2024 and provides for a maximum credit amount of $1.0 billion and a current borrowing base of $460.0 million as of December 31, 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. There were no outstanding letters of credit as of December 31, 2021 and 2020. 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 Alternative Base Rate plus the applicable margin (“ABR Loans”), the Adjusted Term Secured Overnight Financing Rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or Adjusted Daily Simple SOFR plus the applicable margin (“RFR Loans”). Effective November 12, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Term Benchmark Loans and RFR Loans. The Alternate Base Rate and SOFR are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.50% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. 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 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.0 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter; 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 1.0 to 1.0 as of the last day of each fiscal quarter. As of December 31, 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 $11.3 million and $12.6 million for the years ended December 31, 2021 and 2020, respectively. The amount of commitment fee amortization included in interest expense, net was $0.5 million and $0.4 million for the years ended December 31, 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”, such second lien facility, the “Second Lien” and such notes, the “Second Lien Notes”) 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. Effective November 12, 2021, the Company entered into the Second Amendment to the Note Purchase Agreement, which extended the maturity date from December 15, 2024 to December 15, 2026 subject to paying down the principal amount of the Second Lien from $200.0 million to $150.0 million. The Company made the $50 million redemption of the Second Lien Notes on November 29, 2021. The Company accounted for this paydown as a debt modification and incurred approximately $0.1 million in third party fees in connection with the amendment. The unamortized debt issuance cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2026. 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 Alternate Base Rate plus 6.5% as the applicable interest rate. The definitions of LIBOR and Alternate Base Rate 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 its 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, 2022; 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 90% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 90% 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 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 (i) 3.5 to 1.0 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021, (ii) and 3.25 to 1.0 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022, and for any fiscal quarter thereafter. As of December 31, 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 December 31, 2021, net amounts recorded for the Second Lien Notes were $145.8 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $17.8 million and $18.6 million for the years ended December 31, 2021 and 2020, respectively. 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-Ris

Price-Risk Management Price-Risk Management (Notes)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	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 consolidated statements of operations. We have a price-risk management policy 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 years ended December 31, 2021 and 2020, the Company recorded losses of $123.0 million and gains of $61.3 million, respectively, relating to our derivative activities. The Company made net cash payments of $70.6 million and received net cash payments of $78.4 million for settled derivative contracts during the years ended December 31, 2021 and 2020, respectively. Included in our collected cash payments during the year ended December 31, 2020 was $38.3 million for monetized derivative contracts received in the first quarter of 2020. At December 31, 2021 and 2020, we had $0.9 million and $0.8 million, respectively, in receivables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts receivable, net” and were subsequently collected in January 2022 and 2021, respectively. At December 31, 2021 and 2020, we also had $6.4 million and $0.8 million, respectively, in payables for settled derivatives which were included on the accompanying consolidated balance sheets in “Accounts payable and accrued liabilities” and were subsequently paid in January 2022 and 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. At December 31, 2021 there was $2.8 million and $0.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $47.5 million and $8.6 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2020, the Company had $4.8 million and $0.3 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 million in current unsettled derivative liabilities 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 consolidated balance sheets. Under the right of set-off, there was an $53.0 million net fair value liability at December 31, 2021 and $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 10 of these Notes to 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 December 31, 2021. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2022 Contracts 1Q22 223,455 $ 49.32 2Q22 136,500 $ 56.66 3Q22 246,100 $ 49.63 4Q22 184,000 $ 54.84 2023 Contracts 1Q23 82,175 $ 55.75 2Q23 575 $ 68.40 3Q23 53,980 $ 66.55 Collar Contracts 2022 Contracts 1Q22 85,500 $ 57.37 $ 63.55 2Q22 161,350 $ 48.21 $ 55.16 3Q22 46,000 $ 70.00 $ 75.40 4Q22 46,000 $ 68.00 $ 73.60 2023 Contracts 1Q23 45,000 $ 65.00 $ 72.80 2Q23 111,475 $ 59.27 $ 66.32 3Q23 46,000 $ 63.00 $ 69.10 4Q23 46,000 $ 62.00 $ 67.55 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2022 Contracts 1Q22 232,500 $ 4.00 2Q22 3,795,000 $ 2.99 3Q22 4,142,100 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2022 Contracts 1Q22 9,645,000 $ 3.06 $ 3.79 2Q22 6,156,500 $ 2.29 $ 2.74 3Q22 6,739,000 $ 2.60 $ 2.98 4Q22 7,765,076 $ 2.69 $ 3.20 2023 Contracts 1Q23 8,347,000 $ 2.89 $ 3.52 2Q23 4,898,500 $ 2.57 $ 2.97 3Q23 4,600,000 $ 2.88 $ 3.28 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2022 Contracts 1Q22 8,100,000 $ 0.093 2Q22 3,640,000 $ (0.051) 3Q22 3,680,000 $ (0.043) 4Q22 3,680,000 $ (0.048) Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 1Q22 261,000 $ 0.19 2Q22 263,900 $ 0.19 3Q22 266,800 $ 0.19 4Q22 266,800 $ 0.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 180,000 $ 29.13 2Q22 136,500 $ 28.85 3Q22 138,000 $ 28.34 4Q22 138,000 $ 28.27

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $1.8 million for 2022, $2.7 million for 2023, $1.7 million for 2024, $1.2 million for 2025 and $7.4 million in the aggregate. These gas transportation and processing minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2021. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. Actual transportation under these contracts may exceed the minimum commitments previously stated. The Company incurred transportation expense related to these contracts of $7.5 million and $4.4 million for the years ended December 31, 2021 and 2020, respectively. In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In 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.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Notes)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement, Noncash Expense [Abstract]
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. The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, 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 consolidated statements of operations was $4.6 million for both the years ended December 31, 2021 and 2020. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2021 and 2020. We view stock option awards and restricted stock unit awards 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. The Company accounts for forfeitures in compensation cost when they occur. Our shares available for future grant under the Plans were 349,265 at December 31, 2021. Stock Option Awards The compensation cost related to these awards is based on the grant date fair value and is expensed over the vesting period (generally one five At December 31, 2021, we had $0.1 million in unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the year ended December 31, 2021: Shares Wtd. Avg. 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 at December 31, 2021 had no measurable aggregate intrinsic value. At December 31, 2021 the weighted-average remaining contract life of stock option awards outstanding was 4.1 years and exercisable was 3.8 years. The stock option awards exercisable as of December 31, 2021 had no intrinsic value. Restricted Stock Units The Plans allow for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one five As of December 31, 2021, we had unrecognized compensation expense of $0.7 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 0.7 years. The following table provides information regarding restricted stock unit activity for the year ended December 31, 2021: Shares Wtd. Avg. Restricted units outstanding, beginning of period 574,916 $ 9.02 Restricted stock units granted 100,178 $ 8.33 Restricted stock units forfeited (17,802) $ 11.09 Restricted stock units vested (312,447) $ 9.14 Restricted stock units outstanding, end of period 344,845 $ 8.60 Performance-Based Stock Units On February 20, 2018, the Company granted 30,700 performance share units 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 have a cliff-vesting period of three outstanding PSUs related to this award as of December 31, 2021. During the year ended December 31, 2021 23,800 shares vested under this award. On May 21, 2019, the Company granted an additional 99,500 performance-based stock units 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 December 31, 2021, we had unrecognized compensation expense of $1.1 million related to our performance-based stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.0 year. The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2021: Shares Wtd. Avg. Performance based stock units outstanding, beginning of period 107,400 $ 32.48 Performance based stock units granted 161,389 $ 13.13 Performance based stock units vested (23,800) $ 41.66 Performance based stock units outstanding, end of period 244,989 $ 18.84 Employee Savings Plan We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in 2021 and 2020. The Company's plan contributions of $0.5 million and $0.6 million for the years ended December 31, 2021 and 2020, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.

Leases Leases (Notes)

Leases Leases (Notes)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Leases	Leases SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, 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. All of the Company’s leases are 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 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, and the Company does not account for lease and non-lease components separately. 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): Year Ended December 31, 2021 Year Ended December 31, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 3,472 $ 3,774 Property and equipment acquisitions - operating leases — 10 Total lease costs in property, plant and equipment additions $ 3,472 $ 3,784 Year Ended December 31, 2021 Year Ended December 31, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating costs - short-term leases $ 1,873 $ 724 Lease operating costs - operating leases 5,325 5,655 General and administrative, net - operating leases 844 704 Total lease cost expensed $ 8,042 $ 7,083 The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2021 Weighted-average remaining lease term (in years) 3.0 Weighted-average discount rate 4.1 % As of December 31, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2021 2022 $ 7,757 2023 6,468 2024 1,200 2025 803 2026 689 Thereafter 539 Total undiscounted lease payments $ 17,456 Present value adjustment (1,144) Net operating lease liabilities $ 16,312 Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 6,011 $ 6,352 Investing cash flows $ — $ 10 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 8,779 $ 1,751 Rental and lease expense was $7.0 million and $5.8 million for the years ended December 31, 2021 and 2020, respectively. The rental and lease expense primarily relates to compressor rentals and the lease of our office space in Houston, Texas. During 2021 the Company entered into a five

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and Dispositions Bay De Chene Disposition Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in Bay De Chene 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 $0.8 million was paid during the years ended December 31, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying consolidated balance sheet as a current liability in “Accounts payable and accrued liabilities” as of December 31, 2021. April 2020 Acquisition On April 3, 2020, we acquired additional properties in the Eagle Ford for approximately $5.0 million, including assumed liabilities. The acquisition included eight producing wells, basic infrastructure and acreage in Webb, La Salle, and McMullen Counties. We allocated all of the purchase price to proved oil and gas properties. The Company accounted for this transaction as an asset acquisition with the properties added to our full cost pool balance. May 2020 Disposition On May 13, 2020, the Company divested an overriding royalty interest in Converse and Niobrara Counties, Wyoming for approximately $4.8 million. The sales of our Wyoming assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Wyoming operations through the date of sale. August 2021 Acquisition On August 3, 2021, the Company acquired the remaining working interest in 12 wells that SilverBow operates and additional acreage in Webb county. The total aggregate consideration was approximately $23.0 million, consisting of $13.0 million in cash and 516,675 shares of common stock valued at approximately $10.0 million based on the Company's share price on the closing date. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase price to proved oil and gas properties. October 2021 Acquisition On October 1, 2021, we closed on an all-stock transaction to acquire oil and gas assets in the Eagle Ford. The acquired assets include working interests in oil and gas properties across Atascosa, Fayette, Lavaca, McMullen and Live Oak counties. After consideration of closing adjustments, we issued 1,341,990 shares of our common stock valued at approximately $35.6 million, based on the Company's share price on the closing date. The acquisition was subject to further customary post-closing adjustments. We incurred approximately $0.6 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated substantially all of the purchase price to proved oil and gas properties. November 2021 Acquisition On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford (the “Transaction”). The acquired assets included wells and acreage in La Salle, McMullen, DeWitt and Lavaca counties. After consideration of closing adjustments, total aggregate consideration was approximately $77.4 million, consisting of $37.6 million in cash, 1,351,961 shares of our common stock valued at approximately $37.9 million based on the Company's share price on the closing date, and contingent consideration with an estimated fair value of $1.9 million. The contingent consideration consists of up to three earn-out payments of $1.6 million per year for each of 2022, 2023 and 2024, contingent upon the average monthly settlement price of WTI exceeding $70 per barrel for such year (“WTI Contingency Payout”). For further discussion of the fair value related to the Company's contingent consideration, refer to Note 10 of these Notes to Consolidated Financial Statements. The acquisition is subject to further customary post-closing adjustments. We incurred approximately $0.3 million in transaction costs for the year ended December 31, 2021. Management determined that substantially all the fair value of the gross assets acquired were concentrated in the proved oil and gas properties and have therefore accounted for this transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. As a result, we allocated the purchase price to proved oil and gas properties. The following table represents the allocation of the total cost of the Transaction to the assets acquired and liabilities assumed: (in thousands) Total Cost Cash consideration $ 37,581 Equity consideration 37,923 Fair value of contingent consideration 1,855 Total Consideration 77,359 Transaction costs 302 Total Cost of Transaction $ 77,661 Allocation of Total Cost Assets Oil and gas properties $ 78,431 Right of use assets 1,881 Total assets 80,312 Liabilities Undistributed oil and gas revenues 344 Non-current lease liability 1,881 Asset retirement obligations 426 Total Liabilities $ 2,651 Net Assets Acquired $ 77,661

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. 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 swap contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the WTI Contingency Payout, included within “Other long-term liabilities” on the consolidated balance sheets, is estimated using observable market data and a Monte Carlo pricing model. 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). Fair Value on a Nonrecurring Basis . The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below). Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. 2021 and 2020 Acquisitions . The Company recognized the assets acquired in our 2021 and 2020 acquisitions at cost at a relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural gas proved properties, future operating and development costs of the acquired properties and risk adjusted discount rates. The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): 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 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. The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2021 and 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 5 of these Notes to Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant December 31, 2021 Assets Natural Gas Derivatives $ 1,159 $ — $ 1,159 $ — Natural Gas Basis Derivatives $ 1,025 $ — $ 1,025 $ — Oil Derivatives $ 371 $ — $ 371 $ — Oil Basis Derivatives $ 3 $ — $ 3 $ — NGL Derivatives $ 449 $ — $ 449 $ — Liabilities Natural Gas Derivatives $ 31,801 $ — $ 31,801 $ — Natural Gas Basis Derivatives $ 452 $ — $ 452 $ — Oil Derivatives $ 21,330 $ — $ 21,330 $ — Oil Basis Derivatives $ 514 $ — $ 514 $ — NGL Derivatives $ 1,941 $ — $ 1,941 $ — WTI Contingency Payout $ 1,841 $ — $ 1,841 $ — December 31, 2020 Assets Natural Gas Derivatives $ 1,471 $ — $ 1,471 $ — Natural Gas Basis Derivatives $ 1,135 $ — $ 1,135 $ — Oil Derivatives $ 2,493 $ — $ 2,493 $ — Oil Basis Derivatives $ 3 $ — $ 3 $ — Liabilities Natural Gas Derivatives $ 3,967 $ — $ 3,967 $ — Natural Gas Basis Derivatives $ 416 $ — $ 416 $ — Oil Derivatives $ 5,887 $ — $ 5,887 $ — Oil Basis Derivatives $ 847 $ — $ 847 $ — 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 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)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	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. 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 consolidated balance sheets. The following provides a roll-forward of our asset retirement obligations (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 306 Liabilities incurred for new wells, acquired wells and facilities construction 1,120 Reductions due to plugged wells and facilities (192) Revisions in estimates (158) Asset Retirement Obligations as of December 31, 2021 $ 6,050 At December 31, 2021 and 2020, approximately $0.5 million and $0.4 million of our asset retirement obligations were classified as current liabilities in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation . The accompanying consolidated financial statements include the accounts of SilverBow Resources and its wholly owned subsidiary, SilverBow Resources Operating LLC, (collectively, the “Company”, “SilverBow”, “we”, “our” or “us”) 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 and Austin Chalk 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 consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of oil and natural gas.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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 flow therefrom, and the Ceiling Test impairment calculation, • estimates related to the collectability of accounts receivable and the credit worthiness 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 used in the assessment of business combinations and asset purchases, • 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 may 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.
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 years ended December 31, 2021 and 2020, such internal costs when capitalized totaled $4.8 million and $3.5 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2021 and 2020. The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,588,978 $ 1,310,008 Unproved oil and gas properties 17,090 28,090 Furniture, fixtures, and other equipment 5,885 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (869,985) (801,279) Property and Equipment, Net $ 741,968 $ 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 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. The Company evaluates each acquisition of oil and gas properties to determine whether each should be accounted for as an acquisition of assets or business in accordance with Accounting Standards Update No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (“ASU 2017-01”). If substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the set of transferred assets and activities are not a business combination. A business combination may result in the recognition of a bargain purchase gain or goodwill based on the measurement of the fair value of the assets and liabilities acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. Asset acquisitions are recorded at the cost of acquiring the property. The results of operations of the oil and gas properties acquired in the Company’s acquisitions have been included in the consolidated financial statements since the closing dates of the respective acquisitions. See Note 9 for further discussion on recent acquisitions.
Full-Cost Ceiling Test	Full-Cost Ceiling Test . At the end of the 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. There was no ceiling test write-down for the year ended December 31, 2021. Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million for the year ended December 31, 2020. 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 flow 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.
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 Receivable	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 December 31, 2021 and 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 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 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. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 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. 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, 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 deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter of 2020 to offset its net deferred tax assets in excess of deferred tax liabilities. Our income tax provision of $20.9 million for the year ended December 31, 2020 is inclusive of a state income tax benefit of $1.8 million. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of December 31, 2021. We recorded an income tax provision of $6.4 million which was primarily attributable to deferred federal income tax expense for the year ended December 31, 2021. 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 has examined the impact of the CARES Act and has concluded the CARES Act will not have a material effect on its financial condition, results of operation, or liquidity.
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 9,688 $ 15,930 Accrued operating expenses 4,192 2,491 Accrued compensation costs 7,029 3,771 Asset retirement obligations – current portion 524 441 Accrued non-income based taxes 3,314 1,819 Accrued corporate and legal fees 1,972 150 Other payables (1) 8,315 2,389 Total accounts payable and accrued liabilities $ 35,034 $ 26,991 (1) Included in Other Payables is $6.4 million and $0.8 million in payables for settled derivatives for the years ended December 31, 2021 and 2020, respectively.
Cash and Cash Equivalents and Restricted Cash	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.
Credit Risk Due To Certain Concentrations	Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners' receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guarantees, if applicable, to reduce risk of loss.
Treasury Stock	Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets. For the years ended December 31, 2021 and 2020, we purchased 74,586 and 28,731 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares.
New Accounting Pronouncements	New Accounting Pronouncements . In March 2020, the FASB issued ASU No. 2020-03. ASU 2020-03 improves and clarifies various financial instruments topics, including the current expected credit loss standard (“CECL”). ASU 2020-03 includes seven different issues that describe the areas of improvement and the related amendments to GAAP, intended to make the standards easier to understand and apply by eliminating inconsistencies and providing clarifications. This guidance is effective beginning on January 1, 2023 for smaller reporting companies. We are still assessing the requirements to determine the impact of this guidance on our consolidated financial statements. In August 2020, the FASB issued ASU No. 2020-06. This ASU simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument's embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability measured at its amortized cost. This ASU also amends the impact of convertible instruments on the calculation of diluted earnings per share (EPS) and adds several new disclosure requirements. The ASU is effective for fiscal years beginning after December 15, 2021. The ASU can be adopted on either a fully retrospective or modified retrospective basis. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures. In May 2021, the FASB issued ASU 2021-04. This guidance provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. The ASU introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). This guidance is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The adoption of this guidance is not expected to have a material impact on the Company’s consolidated financial statements or disclosures.

Earnings Per Share Earning Per

Earnings Per Share Earning Per Share (Policies)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Earnings Per Share	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 restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units 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.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt Issuance Costs	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)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management ActivitiesDerivatives 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 consolidated statements of operations. We have a price-risk management policy 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.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Policies)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $1.8 million for 2022, $2.7 million for 2023, $1.7 million for 2024, $1.2 million for 2025 and $7.4 million in the aggregate. These gas transportation and processing minimum obligations represent gross future minimum transportation charges we are obligated to pay as of December 31, 2021. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property. Actual transportation under these contracts may exceed the minimum commitments previously stated. The Company incurred transportation expense related to these contracts of $7.5 million and $4.4 million for the years ended December 31, 2021 and 2020, respectively. In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In 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.

Share-Based Compensation Shar_2

Share-Based Compensation Share-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement, Noncash Expense [Abstract]
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. The Company computes a deferred tax benefit for restricted stock awards (“RSUs”), performance-based stock units (“PSUs”) and stock options designed to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units, 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 consolidated statements of operations was $4.6 million for both the years ended December 31, 2021 and 2020. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2021 and 2020. We view stock option awards and restricted stock unit awards 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. The Company accounts for forfeitures in compensation cost when they occur. Our shares available for future grant under the Plans were 349,265 at December 31, 2021.

Leases Leases (Policies)

Leases Leases (Policies)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Leases SilverBow Resources has contractual agreements for its corporate office lease, vehicle fleet, drilling rigs, 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. All of the Company’s leases are 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 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, and the Company does not account for lease and non-lease components separately. The Company recognizes lease expense on a straight-line basis over the lease term.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. 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 swap contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the WTI Contingency Payout, included within “Other long-term liabilities” on the consolidated balance sheets, is estimated using observable market data and a Monte Carlo pricing model. 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). Fair Value on a Nonrecurring Basis . The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties acquired and assessed for classification as a business or an asset and asset retirement obligations. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value estimation when acquisitions occur or asset retirement obligations are recorded. These are considered Level 3 valuations (defined below). Asset retirement obligations. The initial measurement of asset retirement obligations (“ARO”) at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. 2021 and 2020 Acquisitions . The Company recognized the assets acquired in our 2021 and 2020 acquisitions at cost at a relative fair value basis (refer to Note 9 of these Notes to Consolidated Financial Statements). Fair value was determined using a discounted cash flow model. The underlying future commodity prices included in the Company’s estimated future cash flows of its proved oil and gas properties were determined using NYMEX forward strip prices as of the closing date of each acquisition. The estimated future cash flows also included management’s assumptions for the estimates of crude oil and natural gas proved properties, future operating and development costs of the acquired properties and risk adjusted discount rates. The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions): 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 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)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations, Policy	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. 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 consolidated balance sheets.

Summary of Signigicant Accounti

Summary of Signigicant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. Through February 25, 2022, 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 December 31, 2021: Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Swap Contracts 2022 Contracts 4Q22 23,000 $ 80.82 2023 Contracts 1Q23 45,000 $ 78.60 2Q23 45,500 $ 76.90 3Q23 46,000 $ 75.45 4Q23 94,300 $ 73.52 Natural Gas Derivative Contracts Total Volumes Weighted Average Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2Q22 600,000 $ 4.50 3Q22 310,000 $ 4.57 Collar Contracts 2022 Contracts 1Q22 310,000 $ 5.00 $ 7.40 3Q22 920,000 $ 4.40 $ 5.02 4Q22 920,000 $ 4.40 $ 5.43 2023 Contracts 1Q23 900,000 $ 4.40 $ 5.84 4Q23 4,462,000 $ 3.25 $ 3.92 2024 Contracts 1Q24 910,000 $ 3.25 $ 5.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 15,500 $ 35.40 2Q22 45,500 $ 35.40 3Q22 46,000 $ 35.40 4Q22 46,000 $ 35.40 Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 2Q22 45,500 $ 2.63
Property and Equipment	The following is a detailed breakout of our “Property and Equipment” balances (in thousands): December 31, December 31, Property and Equipment Proved oil and gas properties $ 1,588,978 $ 1,310,008 Unproved oil and gas properties 17,090 28,090 Furniture, fixtures, and other equipment 5,885 5,275 Less – Accumulated depreciation, depletion, amortization & impairment (869,985) (801,279) Property and Equipment, Net $ 741,968 $ 542,094
Disaggregation of Revenue	The following table provides information regarding our oil and gas sales, by product, reported on the Consolidated Statements of Operations for years ended December 31, 2021 and 2020 (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Oil, natural gas and NGLs sales: Oil $ 98,607 $ 57,651 Natural gas 267,687 105,234 NGLs 40,906 14,500 Total $ 407,200 $ 177,386
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying consolidated balance sheets are summarized below (in thousands): December 31, December 31, Trade accounts payable $ 9,688 $ 15,930 Accrued operating expenses 4,192 2,491 Accrued compensation costs 7,029 3,771 Asset retirement obligations – current portion 524 441 Accrued non-income based taxes 3,314 1,819 Accrued corporate and legal fees 1,972 150 Other payables (1) 8,315 2,389 Total accounts payable and accrued liabilities $ 35,034 $ 26,991 (1) Included in Other Payables is $6.4 million and $0.8 million in payables for settled derivatives for the years ended December 31, 2021 and 2020, respectively.
Oil and Gas receipts greater than 10%	For the years ended December 31, 2021 and 2020, parties that accounted for 10% or more of our total oil and gas receipts were as follows: Purchasers greater than 10% Year Ended December 31, 2021 Year Ended December 31, 2020 Kinder Morgan 26 % 19 % Plains Marketing 10 % 17 % Twin Eagle 15 % 17 % Trafigura US 16 % 13 % Shell Trading 12 % *

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 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): Year Ended December 31, 2021 Year Ended December 31, 2020 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 86,759 13,118 $ 6.61 $ (309,382) 11,902 $ (25.99) Dilutive Securities: Restricted Stock Unit Awards 285 — Performance Based Stock Unit Awards 117 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 86,759 13,520 $ 6.42 $ (309,382) 11,902 $ (25.99)

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Summary of income (Loss) from continuing operations before taxes	Income (Loss) before taxes is as follows (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Income (Loss) Before Income Taxes $ 93,157 $ (288,471)
Summary of consolidated income tax provision (benefit)	The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Current $ 186 $ (480) Deferred 6,212 21,391 Total $ 6,398 $ 20,911
Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates	Reconciliations of income taxes computed using the U.S. Federal statutory rate of (21%) to the effective income tax rate are as follows: Year Ended December 31, 2021 Year Ended December 31, 2020 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 1.0 % 0.6 % Executive compensation limitation 0.6 % — % Other, net 0.6 % (0.2) % Valuation allowance adjustments (16.2) % (28.6) % Effective rate 6.9 % (7.2) %
Tax effects of temporary differences representing the net deferred tax asset (liability)	The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2021 and 2020 were as follows (in thousands): December 31, 2021 December 31, 2020 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 97,142 $ 93,293 Other carryover items 642 610 Asset retirement obligations 1,306 1,074 Share-based compensation 579 959 Lease liability 3,425 929 Derivative contracts 11,451 — Other 2,111 1,029 Valuation allowance (67,578) (82,618) Total deferred tax assets $ 49,078 $ 15,276 Deferred tax liabilities: Oil and gas exploration and development costs $ (52,219) $ (13,008) Derivative contracts — (1,653) Leased assets (3,374) (917) Other (1) (1) Total deferred tax liabilities (55,594) (15,579) Net deferred tax asset (liabilities) $ (6,516) $ (303) State net deferred tax liabilities $ (1,016) $ (303) Federal net deferred tax liabilities (5,500) — Net deferred tax asset (liabilities) $ (6,516) $ (303)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-term debt	The Company's long-term debt consisted of the following (in thousands): December 31, 2021 December 31, 2020 Credit Facility Borrowings (1) $ 227,000 $ 230,000 Second Lien Notes due 2026 150,000 200,000 377,000 430,000 Unamortized discount on Second Lien Notes (1,061) (1,295) Unamortized debt issuance cost on Second Lien Notes (3,114) (3,800) Total Long-Term Debt $ 372,825 $ 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 December 31, 2021 and 2020, we had $3.6 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)	12 Months Ended
	Dec. 31, 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 December 31, 2021. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2022 Contracts 1Q22 223,455 $ 49.32 2Q22 136,500 $ 56.66 3Q22 246,100 $ 49.63 4Q22 184,000 $ 54.84 2023 Contracts 1Q23 82,175 $ 55.75 2Q23 575 $ 68.40 3Q23 53,980 $ 66.55 Collar Contracts 2022 Contracts 1Q22 85,500 $ 57.37 $ 63.55 2Q22 161,350 $ 48.21 $ 55.16 3Q22 46,000 $ 70.00 $ 75.40 4Q22 46,000 $ 68.00 $ 73.60 2023 Contracts 1Q23 45,000 $ 65.00 $ 72.80 2Q23 111,475 $ 59.27 $ 66.32 3Q23 46,000 $ 63.00 $ 69.10 4Q23 46,000 $ 62.00 $ 67.55 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2022 Contracts 1Q22 232,500 $ 4.00 2Q22 3,795,000 $ 2.99 3Q22 4,142,100 $ 3.02 4Q22 2,760,000 $ 3.14 Collar Contracts 2022 Contracts 1Q22 9,645,000 $ 3.06 $ 3.79 2Q22 6,156,500 $ 2.29 $ 2.74 3Q22 6,739,000 $ 2.60 $ 2.98 4Q22 7,765,076 $ 2.69 $ 3.20 2023 Contracts 1Q23 8,347,000 $ 2.89 $ 3.52 2Q23 4,898,500 $ 2.57 $ 2.97 3Q23 4,600,000 $ 2.88 $ 3.28 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2022 Contracts 1Q22 8,100,000 $ 0.093 2Q22 3,640,000 $ (0.051) 3Q22 3,680,000 $ (0.043) 4Q22 3,680,000 $ (0.048) Oil Basis Derivative Swaps Total Volumes (Bbls) Weighted Average Price Calendar Monthly Roll Differential Swaps 2022 Contracts 1Q22 261,000 $ 0.19 2Q22 263,900 $ 0.19 3Q22 266,800 $ 0.19 4Q22 266,800 $ 0.19 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2022 Contracts 1Q22 180,000 $ 29.13 2Q22 136,500 $ 28.85 3Q22 138,000 $ 28.34 4Q22 138,000 $ 28.27

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Stock Option Activity	The following table represents stock option award activity for the year ended December 31, 2021: Shares Wtd. Avg. 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 Units Activity	The following table provides information regarding restricted stock unit activity for the year ended December 31, 2021: Shares Wtd. Avg. Restricted units outstanding, beginning of period 574,916 $ 9.02 Restricted stock units granted 100,178 $ 8.33 Restricted stock units forfeited (17,802) $ 11.09 Restricted stock units vested (312,447) $ 9.14 Restricted stock units outstanding, end of period 344,845 $ 8.60
Performance-Based Stock Units Activity	The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2021: Shares Wtd. Avg. Performance based stock units outstanding, beginning of period 107,400 $ 32.48 Performance based stock units granted 161,389 $ 13.13 Performance based stock units vested (23,800) $ 41.66 Performance based stock units outstanding, end of period 244,989 $ 18.84

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 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): Year Ended December 31, 2021 Year Ended December 31, 2020 Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 3,472 $ 3,774 Property and equipment acquisitions - operating leases — 10 Total lease costs in property, plant and equipment additions $ 3,472 $ 3,784 Year Ended December 31, 2021 Year Ended December 31, 2020 Lease Costs Included in the Condensed Consolidated Statements of Operations Lease operating costs - short-term leases $ 1,873 $ 724 Lease operating costs - operating leases 5,325 5,655 General and administrative, net - operating leases 844 704 Total lease cost expensed $ 8,042 $ 7,083
Lessee, Operating Lease, Disclosure [Table Text Block]	The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2021 Weighted-average remaining lease term (in years) 3.0 Weighted-average discount rate 4.1 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of December 31, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2021 2022 $ 7,757 2023 6,468 2024 1,200 2025 803 2026 689 Thereafter 539 Total undiscounted lease payments $ 17,456 Present value adjustment (1,144) Net operating lease liabilities $ 16,312
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2021 Year Ended December 31, 2020 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 6,011 $ 6,352 Investing cash flows $ — $ 10 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 8,779 $ 1,751

Business Combinations and Asset

Business Combinations and Asset Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table represents the allocation of the total cost of the Transaction to the assets acquired and liabilities assumed: (in thousands) Total Cost Cash consideration $ 37,581 Equity consideration 37,923 Fair value of contingent consideration 1,855 Total Consideration 77,359 Transaction costs 302 Total Cost of Transaction $ 77,661 Allocation of Total Cost Assets Oil and gas properties $ 78,431 Right of use assets 1,881 Total assets 80,312 Liabilities Undistributed oil and gas revenues 344 Non-current lease liability 1,881 Asset retirement obligations 426 Total Liabilities $ 2,651 Net Assets Acquired $ 77,661

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2021 and 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 5 of these Notes to Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant December 31, 2021 Assets Natural Gas Derivatives $ 1,159 $ — $ 1,159 $ — Natural Gas Basis Derivatives $ 1,025 $ — $ 1,025 $ — Oil Derivatives $ 371 $ — $ 371 $ — Oil Basis Derivatives $ 3 $ — $ 3 $ — NGL Derivatives $ 449 $ — $ 449 $ — Liabilities Natural Gas Derivatives $ 31,801 $ — $ 31,801 $ — Natural Gas Basis Derivatives $ 452 $ — $ 452 $ — Oil Derivatives $ 21,330 $ — $ 21,330 $ — Oil Basis Derivatives $ 514 $ — $ 514 $ — NGL Derivatives $ 1,941 $ — $ 1,941 $ — WTI Contingency Payout $ 1,841 $ — $ 1,841 $ — December 31, 2020 Assets Natural Gas Derivatives $ 1,471 $ — $ 1,471 $ — Natural Gas Basis Derivatives $ 1,135 $ — $ 1,135 $ — Oil Derivatives $ 2,493 $ — $ 2,493 $ — Oil Basis Derivatives $ 3 $ — $ 3 $ — Liabilities Natural Gas Derivatives $ 3,967 $ — $ 3,967 $ — Natural Gas Basis Derivatives $ 416 $ — $ 416 $ — Oil Derivatives $ 5,887 $ — $ 5,887 $ — Oil Basis Derivatives $ 847 $ — $ 847 $ —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations (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 306 Liabilities incurred for new wells, acquired wells and facilities construction 1,120 Reductions due to plugged wells and facilities (192) Revisions in estimates (158) Asset Retirement Obligations as of December 31, 2021 $ 6,050

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe	Dec. 31, 2020USD ($)	Feb. 25, 2022MMBTUbbl$ / MMBTU$ / Boe
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax | $	$ 407,200	$ 177,386
Property, Plant and Equipment [Abstract]
Proved oil and gas properties | $	1,588,978	1,310,008
Unproved oil and gas properties | $	17,090	28,090
Furniture, fixtures, and other equipment | $	5,885	5,275
Less - Accumulated depreciation, depletion, and amortization | $	(869,985)	(801,279)
Property, Plant and Equipment, Net | $	741,968	542,094
Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable | $	9,688	15,930
Accrued operating expenses | $	4,192	2,491
Accrued payroll costs | $	7,029	3,771
Asset retirement obligation - current portion | $	524	441
Accrued taxes | $	3,314	1,819
Accrued Professional Fees, Current | $	1,972	150
Other payables | $	8,315	2,389
Total accounts payable and accrued liabilities | $	$ 35,034	$ 26,991
Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	10.00%
Customer Concentration Risk | Revenue Benchmark | Kinder Morgan Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	26.00%	19.00%
Customer Concentration Risk | Revenue Benchmark | Plains Marketing Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	10.00%	17.00%
Customer Concentration Risk | Revenue Benchmark | Twin Eagle Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	15.00%	17.00%
Customer Concentration Risk | Revenue Benchmark | Trafigura US
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	16.00%	13.00%
Customer Concentration Risk | Revenue Benchmark | Shell Trading Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	12.00%
Oil sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax | $	$ 98,607	$ 57,651
Natural gas sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax | $	267,687	105,234
NGL sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax | $	$ 40,906	$ 14,500
First Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	223,455
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.32
First Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	85,500
Derivative, Average Floor Price | $ / Boe	57.37
Derivative, Average Cap Price | $ / Boe	63.55
First Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	232,500
Derivative, Swap Type, Average Fixed Price	4
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	9,645,000
Derivative, Average Floor Price	3.06
Derivative, Average Cap Price	3.79
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			310,000
Derivative, Average Floor Price			5
Derivative, Average Cap Price			7.40
First Quarter 2022 | NGL Derivative | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Average Fixed Price	29.13
First Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			15,500
Derivative, Swap Type, Average Fixed Price			35.40
First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	261,000
Derivative, Swap Type, Average Fixed Price	0.19
Second Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	56.66
Second Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	161,350
Derivative, Average Floor Price | $ / Boe	48.21
Derivative, Average Cap Price | $ / Boe	55.16
Second Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	3,795,000
Derivative, Swap Type, Average Fixed Price	2.99
Second Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			600,000
Derivative, Swap Type, Average Fixed Price			4.50
Second Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,156,500
Derivative, Average Floor Price	2.29
Derivative, Average Cap Price	2.74
Second Quarter 2022 | NGL Derivative | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price	28.85
Second Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price			35.40
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	263,900
Derivative, Swap Type, Average Fixed Price	0.19
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price			2.63
Third Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	246,100
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.63
Third Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	70
Derivative, Average Cap Price | $ / Boe	75.40
Third Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,142,100
Derivative, Swap Type, Average Fixed Price	3.02
Third Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			310,000
Derivative, Swap Type, Average Fixed Price			4.57
Third Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,739,000
Derivative, Average Floor Price	2.60
Derivative, Average Cap Price	2.98
Third Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.02
Third Quarter 2022 | NGL Derivative | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.34
Third Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price			35.40
Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19
Fourth Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	184,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	54.84
Fourth Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			23,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			80.82
Fourth Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	68
Derivative, Average Cap Price | $ / Boe	73.60
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	2,760,000
Derivative, Swap Type, Average Fixed Price	3.14
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	7,765,076
Derivative, Average Floor Price	2.69
Derivative, Average Cap Price	3.20
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.43
Fourth Quarter 2022 | NGL Derivative | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.27
Fourth Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price			35.40
Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19
First Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	82,175
Derivative, Swap Type, Average Fixed Price | $ / Boe	55.75
First Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			78.60
First Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Average Floor Price | $ / Boe	65
Derivative, Average Cap Price | $ / Boe	72.80
First Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	8,347,000
Derivative, Average Floor Price	2.89
Derivative, Average Cap Price	3.52
First Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			900,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.84
Second Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	575
Derivative, Swap Type, Average Fixed Price | $ / Boe	68.40
Second Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price | $ / Boe			76.90
Second Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	111,475
Derivative, Average Floor Price | $ / Boe	59.27
Derivative, Average Cap Price | $ / Boe	66.32
Second Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,898,500
Derivative, Average Floor Price	2.57
Derivative, Average Cap Price	2.97
Third Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	53,980
Derivative, Swap Type, Average Fixed Price | $ / Boe	66.55
Third Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			75.45
Third Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	63
Derivative, Average Cap Price | $ / Boe	69.10
Third Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,600,000
Derivative, Average Floor Price	2.88
Derivative, Average Cap Price	3.28
Fourth Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl			94,300
Derivative, Swap Type, Average Fixed Price | $ / Boe			73.52
Fourth Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	62
Derivative, Average Cap Price | $ / Boe	67.55
Fourth Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			4,462,000
Derivative, Average Floor Price			3.25
Derivative, Average Cap Price			3.92
First Quarter 2024 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Property, Plant and Equipment [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			910,000
Derivative, Average Floor Price			3.25
Derivative, Average Cap Price			5.19

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)bblMMBTU$ / MMBTU$ / Boeshares	Dec. 31, 2020USD ($)shares	Feb. 25, 2022MMBTUbbl$ / MMBTU$ / Boe	Aug. 13, 2021USD ($)	Mar. 31, 2021
Summary of Significant Accounting Policies (Textual) [Abstract]
Brent Spot Price	77				64
WTI Spot Price	75				59
Total capitalized internal costs | $	$ 4,800	$ 3,500
Discount rate for estimated future net revenues from proved properties	10.00%
Write-down of oil and gas properties | $	$ 0	355,948
Revenue from Contract with Customer, Excluding Assessed Tax | $	407,200	177,386
Allowance for doubtful accounts receivable, current | $	100	100
Accounts receivable from oil and gas sales | $	45,300	18,800
Accounts receivable related to joint interest owners | $	1,900	4,000
Severance tax credit receivables | $	1,000	2,400
Other receivables | $	$ 1,500	700
Percentage of working interest in wells	100.00%
Total amount of supervision fees charged to wells | $	$ 5,100	4,400
Income Tax Expense (Benefit) | $	6,398	20,911
Current State and Local Tax Expense (Benefit) | $		(1,800)
Payables for Settled Derivatives | $	$ 6,400	$ 800
Treasury Stock, Shares, Acquired | shares	74,586	28,731
ATM Program , Maximum Proceeds | $				$ 40,000
Issuance of common stock | shares	1,222,209
Stock Issued During Period, Value, New Issues | $	$ 26,956
Line of Credit [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Capitalized interest on our unproved properties | $	$ 0	$ 0
First Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	223,455
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.32
First Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	85,500
Derivative, Average Floor Price | $ / Boe	57.37
Derivative, Average Cap Price | $ / Boe	63.55
First Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	232,500
Derivative, Swap Type, Average Fixed Price	4
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	9,645,000
Derivative, Average Floor Price	3.06
Derivative, Average Cap Price	3.79
First Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			310,000
Derivative, Average Floor Price			5
Derivative, Average Cap Price			7.40
First Quarter 2022 | NGL Derivative | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Average Fixed Price	29.13
First Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			15,500
Derivative, Swap Type, Average Fixed Price			35.40
First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	261,000
Derivative, Swap Type, Average Fixed Price	0.19
Second Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	56.66
Second Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	161,350
Derivative, Average Floor Price | $ / Boe	48.21
Derivative, Average Cap Price | $ / Boe	55.16
Second Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	3,795,000
Derivative, Swap Type, Average Fixed Price	2.99
Second Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			600,000
Derivative, Swap Type, Average Fixed Price			4.50
Second Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,156,500
Derivative, Average Floor Price	2.29
Derivative, Average Cap Price	2.74
Second Quarter 2022 | NGL Derivative | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price	28.85
Second Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price			35.40
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	263,900
Derivative, Swap Type, Average Fixed Price	0.19
Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price			2.63
Third Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	246,100
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.63
Third Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	70
Derivative, Average Cap Price | $ / Boe	75.40
Third Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,142,100
Derivative, Swap Type, Average Fixed Price	3.02
Third Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			310,000
Derivative, Swap Type, Average Fixed Price			4.57
Third Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,739,000
Derivative, Average Floor Price	2.60
Derivative, Average Cap Price	2.98
Third Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.02
Third Quarter 2022 | NGL Derivative | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.34
Third Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price			35.40
Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19
Fourth Quarter 2022 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	184,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	54.84
Fourth Quarter 2022 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			23,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			80.82
Fourth Quarter 2022 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	68
Derivative, Average Cap Price | $ / Boe	73.60
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	2,760,000
Derivative, Swap Type, Average Fixed Price	3.14
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	7,765,076
Derivative, Average Floor Price	2.69
Derivative, Average Cap Price	3.20
Fourth Quarter 2022 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.43
Fourth Quarter 2022 | NGL Derivative | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.27
Fourth Quarter 2022 | NGL Derivative | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price			35.40
Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19
First Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	82,175
Derivative, Swap Type, Average Fixed Price | $ / Boe	55.75
First Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			78.60
First Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Average Floor Price | $ / Boe	65
Derivative, Average Cap Price | $ / Boe	72.80
First Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	8,347,000
Derivative, Average Floor Price	2.89
Derivative, Average Cap Price	3.52
First Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			900,000
Derivative, Average Floor Price			4.40
Derivative, Average Cap Price			5.84
Second Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	575
Derivative, Swap Type, Average Fixed Price | $ / Boe	68.40
Second Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			45,500
Derivative, Swap Type, Average Fixed Price | $ / Boe			76.90
Second Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	111,475
Derivative, Average Floor Price | $ / Boe	59.27
Derivative, Average Cap Price | $ / Boe	66.32
Second Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,898,500
Derivative, Average Floor Price	2.57
Derivative, Average Cap Price	2.97
Third Quarter 2023 | Oil Derivative [Member] | Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	53,980
Derivative, Swap Type, Average Fixed Price | $ / Boe	66.55
Third Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			46,000
Derivative, Swap Type, Average Fixed Price | $ / Boe			75.45
Third Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	63
Derivative, Average Cap Price | $ / Boe	69.10
Third Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	4,600,000
Derivative, Average Floor Price	2.88
Derivative, Average Cap Price	3.28
Fourth Quarter 2023 | Oil Derivative [Member] | Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl			94,300
Derivative, Swap Type, Average Fixed Price | $ / Boe			73.52
Fourth Quarter 2023 | Oil Derivative [Member] | Collar Contracts [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	62
Derivative, Average Cap Price | $ / Boe	67.55
Fourth Quarter 2023 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			4,462,000
Derivative, Average Floor Price			3.25
Derivative, Average Cap Price			3.92
First Quarter 2024 | Natural Gas Derivative [Member] | Collar Contracts [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			910,000
Derivative, Average Floor Price			3.25
Derivative, Average Cap Price			5.19
Customer Concentration Risk
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage	10.00%
Minimum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life	2 years
Maximum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life	20 years
Oil sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $	$ 98,607	57,651
Natural gas sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $	267,687	105,234
NGL sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax | $	$ 40,906	$ 14,500

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Basic EPS:
Net Income (Loss)	$ 86,759	$ (309,382)
Income, Share Amounts	13,118	11,902
Earnings (Loss) Per Share, Basic	$ 6.61	$ (25.99)
Dilutive Securities:
Dilutive Restricted Stock Unit Awards	285	0
Dilutive Performance Based Stock Unit Awards	117	0
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 86,759	$ (309,382)
Weighted Average Number of Shares Outstanding, Diluted	13,520	11,902
Earnings (Loss) Per Share, Diluted	$ 6.42	$ (25.99)
Stock Options [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	300	300
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	0	200
Performance Shares [Member]
Earnings Per Share (Textual) [Abstract]
Antidilutive shares not included in the computation of diluted EPS	0	100

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Summary of income (Loss) from continuing operations before taxes
Income (Loss) Before Income Taxes	$ 93,157	$ (288,471)

Consolidated income tax provisi

Consolidated income tax provision (benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Summary of consolidated income tax provision (benefit)
Current income taxes	$ 186	$ (480)
Deferred Income Tax Expense (Benefit)	6,212	21,391
Income tax provision (benefit)	$ 6,398	$ 20,911

Reconciliation of income taxes

Reconciliation of income taxes using federal statutory rate to effective income tax rate (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%
State tax provisions (benefits), net of federal benefits	1.00%	0.60%
Executive compensation limitation	0.60%	0.00%
Other, net	0.60%	(0.20%)
Valuation allowance adjustments	(16.20%)	(28.60%)
Effective rate	6.90%	(7.20%)

Tax effects of temporary differ

Tax effects of temporary differences representing the net DTA (DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets:
DTA, Federal net operating losses (NOLs)	$ 97,142	$ 93,293
DTA, Other loss carryforwards	642	610
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	1,306	1,074
DTA, Unrealized share-based compensation	579	959
Deferred Tax Assets, Tax Deferred Expense, Other	3,425	929
Deferred Tax Assets, Derivative Instruments	11,451	0
DTA, Other	2,111	1,029
DTA, Valuation Allowance	(67,578)	(82,618)
Total deferred tax assets	49,078	15,276
Deferred tax liabilities:
DTL, Oil and gas exploration and development costs	(52,219)	(13,008)
Deferred Tax Liabilities, Derivatives	0	(1,653)
Deferred Tax Liabilities, Leasing Arrangements	(3,374)	(917)
DTL, Other	(1)	(1)
Total deferred tax liabilites	55,594	15,579
Net deferred tax liabilities	(6,516)	(303)
State deferred tax liabilities, net	(1,016)	(303)
Federal deferred tax assets, net	$ (5,500)	$ 0

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Effective income tax rate reconciliation, percent	21.00%	21.00%
Deferred Tax Assets, Valuation Allowance	$ 67,578	$ 82,618
Operating Loss Carryforward, Income Tax Limitation	80.00%
Tax Year 2015 [Member]
Operating Loss Carryforwards	$ 114,600
Tax Year 2017 [Member]
Operating Loss Carryforwards	159,600
Tax Year 2021
Operating Loss Carryforwards	$ 188,300

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Nov. 29, 2021USD ($)	Nov. 12, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Apr. 16, 2021USD ($)	Dec. 15, 2017USD ($)
Bank Borrowings
Long-Term Debt, excluding current maturities			$ 372,825	$ 424,905
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility			29,129	31,228
Second Lien
Long-term Debt, Gross			377,000	430,000
Payments of long-term debt	$ (50,000)		$ (50,000)	0
Professional Fees		$ 100
Discount Rate for Estimated Future Net Revenues from Proved Properties			10.00%
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net			$ (3,600)	(1,400)
New Credit Facility [Member] | Line of Credit [Member]
Bank Borrowings
Long-Term Debt, excluding current maturities			227,000	230,000
Line of Credit, current borrowing base		460,000			$ 300,000
Line of Credit Facility, Maximum Borrowing Capacity		1,000,000
Line of Credit, Letters of Credit Issuable		$ 25,000
Line of Credit Facility, Commitment Fee Percentage		0.50%
Line of Credit, Additional Interest Due to Payment Default		2.00%
Line of Credit, Required Security Interest on Oil and Gas Properties		90.00%
Line of Credit, Covenant, Debt to EBITDA Ratio, Minimum		3.25
Line of Credit, Covenant, Current Ratio, Minimum		1
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility			11,300	12,600
Commitment fees included in interest expense, net			500	400
Second Lien
Line of Credit, Covenant, Debt to EBITDA Ratio, after March 31, 2022		3
New Credit Facility [Member] | Line of Credit [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 term benchmark loans		0.0325
New Credit Facility [Member] | Line of Credit [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 term benchmark loans		0.0425
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net			(3,114)	(3,800)
Long-Term Debt, excluding current maturities			150,000	200,000		$ 198,000
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility			17,800	18,600
Second Lien
Long-term Debt, Gross		$ 150,000				200,000
Debt Instrument, Unamortized Discount			(1,061)	$ (1,295)		$ (2,000)
Additional interest in the event of default		0.020
Make whole premium		0.010
Second Lien, Required Security Interest on Proved Reserves		90.00%
Second Lien, Required Security Interest on Oil and Gas Properties		90.00%
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		3.5
Second Lien, Debt to EBITDA Ratio, after March 31, 2022		3.25
Long-term Debt			$ 145,800
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt Instrument escalating basis spread on base rate		0.065
Second Lien Notes [Member] | London Interbank Offered Rate (LIBOR) [Member]
Bank Borrowings
Debt Instrument escalating basis spread on base rate		0.075

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)bblMMBTU$ / MMBTU$ / Boe	Dec. 31, 2020USD ($)
Derivative [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (123,000)	$ 61,300
Cash Received (Paid) On Settlements of Derivative Contracts | $	(70,582)	78,421
Cash Received (Paid) On Monetized Derivative Contracts | $	38,300
Receivables for Settled Derivatives | $	900	800
Payables for Settled Derivatives | $	6,400	800
Derivative, Fair Value, Net | $	(53,000)	(6,000)
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	2,800	4,800
Other Noncurrent Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	200	300
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	47,500	8,200
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 8,600	$ 2,900
Swap [Member] | First Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	223,455
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.32
Swap [Member] | First Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	232,500
Derivative, Swap Type, Average Fixed Price	4
Swap [Member] | First Quarter 2022 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	180,000
Derivative, Swap Type, Average Fixed Price	29.13
Swap [Member] | Second Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	56.66
Swap [Member] | Second Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,795,000
Derivative, Swap Type, Average Fixed Price	2.99
Swap [Member] | Second Quarter 2022 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	136,500
Derivative, Swap Type, Average Fixed Price	28.85
Swap [Member] | Third Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	246,100
Derivative, Swap Type, Average Fixed Price | $ / Boe	49.63
Swap [Member] | Third Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,142,100
Derivative, Swap Type, Average Fixed Price	3.02
Swap [Member] | Third Quarter 2022 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.34
Swap [Member] | Fourth Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	184,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	54.84
Swap [Member] | Fourth Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,760,000
Derivative, Swap Type, Average Fixed Price	3.14
Swap [Member] | Fourth Quarter 2022 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	138,000
Derivative, Swap Type, Average Fixed Price	28.27
Swap [Member] | First Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	82,175
Derivative, Swap Type, Average Fixed Price | $ / Boe	55.75
Swap [Member] | Second Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	575
Derivative, Swap Type, Average Fixed Price | $ / Boe	68.40
Swap [Member] | Third Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	53,980
Derivative, Swap Type, Average Fixed Price | $ / Boe	66.55
Collar Contracts [Member] | First Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	85,500
Derivative, Average Floor Price | $ / Boe	57.37
Derivative, Average Cap Price | $ / Boe	63.55
Collar Contracts [Member] | First Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,645,000
Derivative, Average Floor Price	3.06
Derivative, Average Cap Price	3.79
Collar Contracts [Member] | Second Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	161,350
Derivative, Average Floor Price | $ / Boe	48.21
Derivative, Average Cap Price | $ / Boe	55.16
Collar Contracts [Member] | Second Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,156,500
Derivative, Average Floor Price	2.29
Derivative, Average Cap Price	2.74
Collar Contracts [Member] | Third Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	70
Derivative, Average Cap Price | $ / Boe	75.40
Collar Contracts [Member] | Third Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,739,000
Derivative, Average Floor Price	2.60
Derivative, Average Cap Price	2.98
Collar Contracts [Member] | Fourth Quarter 2022 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	68
Derivative, Average Cap Price | $ / Boe	73.60
Collar Contracts [Member] | Fourth Quarter 2022 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,765,076
Derivative, Average Floor Price	2.69
Derivative, Average Cap Price	3.20
Collar Contracts [Member] | First Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	45,000
Derivative, Average Floor Price | $ / Boe	65
Derivative, Average Cap Price | $ / Boe	72.80
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,347,000
Derivative, Average Floor Price	2.89
Derivative, Average Cap Price	3.52
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	111,475
Derivative, Average Floor Price | $ / Boe	59.27
Derivative, Average Cap Price | $ / Boe	66.32
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,898,500
Derivative, Average Floor Price	2.57
Derivative, Average Cap Price	2.97
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	63
Derivative, Average Cap Price | $ / Boe	69.10
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,600,000
Derivative, Average Floor Price	2.88
Derivative, Average Cap Price	3.28
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	46,000
Derivative, Average Floor Price | $ / Boe	62
Derivative, Average Cap Price | $ / Boe	67.55
Basis Swap [Member] | First Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,100,000
Derivative, Swap Type, Average Fixed Price	0.093
Basis Swap [Member] | First Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	261,000
Derivative, Swap Type, Average Fixed Price	0.19
Basis Swap [Member] | Second Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,640,000
Derivative, Swap Type, Average Fixed Price	(0.051)
Basis Swap [Member] | Second Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	263,900
Derivative, Swap Type, Average Fixed Price	0.19
Basis Swap [Member] | Third Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,680,000
Derivative, Swap Type, Average Fixed Price	(0.043)
Basis Swap [Member] | Third Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19
Basis Swap [Member] | Fourth Quarter 2022 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,680,000
Derivative, Swap Type, Average Fixed Price	(0.048)
Basis Swap [Member] | Fourth Quarter 2022 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	266,800
Derivative, Swap Type, Average Fixed Price	0.19

Commitments and Contingencies (

Commitments and Contingencies (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Obligations (Textual)
Transportation Expense Incurred	$ 7.5	$ 4.4
Gas transportation and processing obligations [Member]
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	1.8
Contractual Obligation, Due in Second Year	2.7
Contractual Obligation, Due in Third Year	1.7
Contractual Obligation, Due in Fourth Year	1.2
Contractual Obligation	$ 7.4

Share-Based Compensation (Detai

Share-Based Compensation (Details 1) - $ / shares	Feb. 24, 2021	May 21, 2019	Feb. 20, 2018	Dec. 31, 2021	Dec. 31, 2020
Share-based Payment Arrangement, Option [Member]
Stock option activity in shares and weighted average price
Options outstanding, beginning of period, shares				303,705
Options outstanding, beginning of period, weighted average price				$ 27.73
Options expired				(23,800)
Options expired, weighted average price				$ 23.25
Options outstanding, end of period, shares				276,009
Options outstanding, end of period, weighted average price				$ 28.12
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period				(3,896)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price				$ 16.96
Options exercisable, end of period, shares				226,950
Options exercisable, end of period, weighted average price				$ 28.53
Restricted Stock Units (RSUs) [Member]
Restricted stock activity
Restricted units outstanding				344,845	574,916
Restricted units outstanding, weighted average price				$ 8.60	$ 9.02
Restricted stock units granted				100,178
Restricted stock units granted, weighted average price				$ 8.33
Restricted stock units forfeited				(17,802)
Restricted stock units forfeited, weighted average price				$ 11.09
Restricted stock units vested				(312,447)
Restricted stock units vested, weighted average price				$ 9.14
Performance-based stock unit [Member]
Restricted stock activity
Restricted units outstanding				244,989	107,400
Restricted units outstanding, weighted average price				$ 18.84	$ 32.48
Restricted stock units granted	161,389	99,500	30,700	161,389
Restricted stock units granted, weighted average price	$ 13.13	$ 18.86	$ 41.66	$ 13.13
Restricted stock units vested				(23,800)
Restricted stock units vested, weighted average price				$ 41.66

Share-Based Compensation (Det_2

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands	Feb. 23, 2022	Feb. 24, 2021	Dec. 31, 2020	May 21, 2019	Feb. 20, 2018	Dec. 31, 2021	Dec. 31, 2020
Stock-Based Compensation Plan
Share-based compensation expenses						$ 4,645	$ 4,557
Share-based Payment Arrangement, Amount Capitalized						$ 200	200
Shares available for future grant under stock compensation plans						349,265
Employee Savings Plan [Abstract]
Employee Savings Plan, Employer Matching Contribution, Percent						100.00%
Employee Savings Plan, Maximum Annual Contribution Per Employee, Percent						6.00%
Employee Savings Plan, Employer Discretionary Contribution Amount						$ 500	600
General and Administrative Expense [Member]
Stock-Based Compensation Plan
Share-based compensation expenses						4,600	$ 4,600
Share-based Payment Arrangement, Option [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						100
Outstanding stock options aggregate intrinsic value						$ 0
Remaining contract life of outstanding stock options.						4 years 1 month 6 days
Remaining contract life of exercisable stock option						3 years 9 months 18 days
Intrinsic value of exercised stock option						$ 0
Restricted Stock Units (RSUs) [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						$ 700
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards						8 months 12 days
Restricted units outstanding			574,916			344,845	574,916
Restricted stock units granted						100,178
Restricted stock units granted, weighted average price						$ 8.33
Restricted stock units vested						312,447
Performance-based stock unit [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						$ 1,100
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards			1 year
Restricted units outstanding			107,400			244,989	107,400
Restricted stock units granted		161,389		99,500	30,700	161,389
Restricted stock units granted, weighted average price		$ 13.13		$ 18.86	$ 41.66	$ 13.13
Percent of payout for performance based stock units		157.60%		112.90%	150.61%	100.00%
Restricted stock units vested						23,800
Performance-based stock unit [Member] | May 21, 2019 Award
Stock Units [Abstract]
Restricted units outstanding						83,600
Performance-based stock unit [Member] | Subsequent Event
Stock Units [Abstract]
Percent of payout for performance based stock units	117.00%
Restricted stock units vested	97,812
Minimum Payout [Member] | Share-based Payment Arrangement, Option [Member]
Stock Units [Abstract]
Vesting period						1 year
Minimum Payout [Member] | Restricted Stock Units (RSUs) [Member]
Stock Units [Abstract]
Vesting period						1 year
Minimum Payout [Member] | Performance-based stock unit [Member]
Stock Units [Abstract]
Percent of payout for performance based stock units		0.00%		0.00%	0.00%
Maximum Payout [Member] | Share-based Payment Arrangement, Option [Member]
Stock Units [Abstract]
Vesting period						5 years
Maximum Payout [Member] | Restricted Stock Units (RSUs) [Member]
Stock Units [Abstract]
Vesting period						5 years
Maximum Payout [Member] | Performance-based stock unit [Member]
Stock Units [Abstract]
Percent of payout for performance based stock units		200.00%		200.00%	200.00%
Performance Period for Award				3 years	3 years	2 years

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Feb. 05, 2021
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 8,042	$ 7,083
Operating Lease, Weighted Average Remaining Lease Term	3 years
Operating Lease, Weighted Average Discount Rate, Percent	4.10%
Lessee, Operating Lease, Liability, Payments, Due Year One	$ 7,757
Lessee, Operating Lease, Liability, Payments, Due Year Two	6,468
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,200
Lessee, Operating Lease, Liability, Payments, Due Year Four	803
Lessee, Operating Lease, Liability, Payments, Due Year Five	689
Lessee, Operating Lease, Liability, Payments, Due after Year Five	539
Lessee, Operating Lease, Liability, Payments, Due	17,456
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(1,144)
Operating Lease, Liability	16,312
Operating Lease, Payments	6,011	6,352
Operating Lease, Payments, Use	0	10
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	8,779	1,751
Operating Leases, Rent Expense	7,000	5,800
Building [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract			5 years
Operating Leases, Future Minimum Payments Due	3,500
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	1,873	724
Operating Lease, Cost	5,325	5,655
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	844	704
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	3,472	3,774
Operating Lease, Cost	0	10
Lease, Cost	$ 3,472	$ 3,784

Acquisitions and Dispositions (

Acquisitions and Dispositions (Details) $ in Thousands	Nov. 19, 2021USD ($)shares	Oct. 01, 2021USD ($)shares	Aug. 03, 2021USD ($)shares	May 13, 2020USD ($)	Apr. 03, 2020USD ($)	Dec. 31, 2021USD ($)shares	Dec. 31, 2020USD ($)	Dec. 22, 2017USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments for (Proceeds from) Other Investing Activities						$ 1,084	$ 826
Issuance pursuant to acquisitions | shares						3,210,626
Right of use assets						$ 16,065	4,366
Non-current lease liability						9,090	951
Asset Retirement Obligations, Noncurrent						5,526	4,533
WTI Contingency Payout	$ 1,855
Other Liabilities, Current						23,577	$ 11,098
Eagle Ford Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to Acquire Oil and Gas Property					$ 5,000
La Mesa
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to Acquire Oil and Gas Property			$ 13,000
Asset Acquisition, Consideration Transferred			$ 23,000
Issuance pursuant to acquisitions | shares			516,675
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable			$ 10,000
Wells Purchased			12
Post Oak Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Issuance pursuant to acquisitions | shares		1,341,990
Business Acquisition, Transaction Costs						600
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable		$ 35,600
Teal Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments to Acquire Oil and Gas Property						37,581
Asset Acquisition, Consideration Transferred	77,359
Business Acquisition, Transaction Costs						302
Asset Acquisition, Total Cost of Transaction						77,661
Allocation of Total Cost, Oil and gas properties						78,431
Right of use assets						1,881
Allocation of Total Cost, Total assets						80,312
Non-current lease liability						1,881
Asset Retirement Obligations, Noncurrent						426
Allocation of Total Cost, Total Liabilities						2,651
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable	$ 37,923
WTI Annual Earn Out Payment						$ 1,600
WTI Annual Earn Out, Average Monthly Settlement Price						70
Other Liabilities, Current						$ 344
Teal Acquisition | Asset Acquisition, Shares Issuable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Issuance pursuant to acquisitions | shares	1,351,961
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
Cash to be released for purchase and sale contract						$ 500
Wyoming Disposition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment				$ 4,800

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Nov. 19, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
WTI Contingency Payout		$ 1,855
Natural Gas Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	$ 1,159		$ 1,471
Derivative Liability	31,801		3,967
Natural Gas Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	1,025		1,135
Derivative Liability	452		416
Oil Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	371		2,493
Derivative Liability	21,330		5,887
WTI Contingency Payout	1,841
Oil Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	3		3
Derivative Liability	514		847
NGL Derivative | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	449
Derivative Liability	1,941
Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
Fair Value, Inputs, Level 1 [Member] | Oil Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
WTI Contingency Payout	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
Fair Value, Inputs, Level 1 [Member] | NGL Derivative | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0
Derivative Liability	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	1,159		1,471
Derivative Liability	31,801		3,967
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	1,025		1,135
Derivative Liability	452		416
Fair Value, Inputs, Level 2 [Member] | Oil Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	371		2,493
Derivative Liability	21,330		5,887
WTI Contingency Payout	1,841
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	3		3
Derivative Liability	514		847
Fair Value, Inputs, Level 2 [Member] | NGL Derivative | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	449
Derivative Liability	1,941
Fair Value, Inputs, Level 3 [Member] | Natural Gas Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
Fair Value, Inputs, Level 3 [Member] | Oil Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		0
WTI Contingency Payout	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member] | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0		0
Derivative Liability	0		$ 0
Fair Value, Inputs, Level 3 [Member] | NGL Derivative | Fair Value, Recurring [Member]
Debt Instrument [Line Items]
Derivative Asset	0
Derivative Liability	$ 0

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 6,050	$ 4,974	$ 4,447
Accretion expense	306	354
Liabilities incurred for new wells and facilities construction	1,120	281
Asset Retirement Obligation, Liabilities Plugged	(192)	(103)
Revisions in estimates	(158)	(5)
Asset retirement obligation - current portion	$ 524	$ 441

Uncategorized Items - sbow-2021

Label	Element	Value
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	$ 1,358,000