SilverBow Resources (SBOW) 10-K 2 Mar 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 24, 2023	Jun. 30, 2022
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2022
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			$ 492,145,402
Entity Common Stock, Shares Outstanding		22,473,737
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2022
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, 2022
Auditor Information [Abstract]
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, 2022	Dec. 31, 2021
Current Assets:
Cash and cash equivalents	$ 792	$ 1,121
Accounts receivable	89,714	49,777
Fair value of commodity derivatives	52,549	2,806
Other current assets	2,671	1,875
Total Current Assets	145,726	55,579
Property and Equipment:
Property, Plant and Equipment, Gross	2,529,223	1,611,953
Less - Accumulated depreciation, depletion, and amortization	(1,004,044)	(869,985)
Property, Plant and Equipment, Net	1,525,179	741,968
Right of use assets	12,077	16,065
Fair value of long-term commodity derivatives	24,172	201
Other Long-Term Assets	9,208	5,641
Total Assets	1,716,362	819,454
Current Liabilities:
Accounts payable and accrued liabilities	60,200	35,034
Fair value of commodity derivatives	40,796	47,453
Accrued capital costs	56,465	7,354
Accrued interest	2,665	697
Current lease liability	8,553	7,222
Undistributed oil and gas revenues	27,160	23,577
Total Current Liabilities	195,839	121,337
Long-Term Debt	688,531	372,825
Non-current lease liability	3,775	9,090
Deferred tax liabilities, net	16,141	6,516
Asset Retirement Obligation	9,171	5,526
Fair value of long-term commodity derivatives	7,738	8,585
Other long-term liabilities	3,588	3,043
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common Stock, Value, Issued	227	168
Additional paid-in capital	$ 576,118	$ 413,017
Treasury Stock, Shares	353,395	191,670
Treasury Stock, Value	$ (7,534)	$ (2,984)
Retained earnings (Accumulated deficit)	222,768	(117,669)
Total Stockholders' Equity (Deficit)	791,579	292,532
Total Liabilities and Stockholders' Equity	1,716,362	819,454
Capitalized Costs, Unproved Properties	$ 16,272	$ 17,090
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	22,663,135	16,822,845
Common Stock, Shares, Outstanding	22,309,740	16,631,175

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2021 $ / shares shares
Statement of Financial Position [Abstract]
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, 2022	Dec. 31, 2021
Revenues:
Oil and gas sales	$ 753,420	$ 407,200
Costs and Expenses:
General and administrative, net	21,395	21,799
Depreciation, depletion, and amortization	133,982	68,629
Accretion of asset retirement obligation	534	306
Lease operating cost	55,329	27,206
Workovers	1,655	514
Results of Operations, Transportation Costs	32,989	24,145
Severance and other taxes	41,761	19,307
Total Operating Expenses	287,645	161,906
Operating Income (Loss)	465,775	245,294
Net gain (loss) on commodity derivatives	(73,885)	(123,018)
Interest expense, net	(41,948)	(29,129)
Other income (expense), net	95	10
Income (Loss) Before Income Taxes	350,037	93,157
Provision (Benefit) for Income Taxes	9,600	6,398
Net Income (Loss)	$ 340,437	$ 86,759
Per Share Amounts-
Earnings (Loss) Per Share, Basic	$ 17.24	$ 6.61
Earnings (Loss) Per Share, Diluted	$ 16.94	$ 6.42
Weighted Average Shares Outstanding - Basic	19,748	13,118
Weighted Average Shares Outstanding - Diluted	20,097	13,520

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	$ 91,033	$ 121	$ 297,712	$ (2,372)	$ (204,428)
Purchase of treasury shares	(612)	0	0	(612)	0
Stock Issued During Period, Value, New Issues	26,956	12	26,944	0	0
Vesting of share-based compensation	0	3	(3)	0	0
Issuance pursuant to 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
Purchase of treasury shares (shares)	74,586
Issuance of common stock	1,222,209
Vesting of share-based compensation	336,247
Issuance pursuant to acquisitions	3,210,626
Beginning Balance	$ 292,532	168	413,017	(2,984)	(117,669)
Shares issued from option exercise	426	0	426	0	0
Purchase of treasury shares	(3,397)	0	0	(3,397)	0
Treasury shares pursuant to purchase price adjustment	(1,153)	0	0	(1,153)	0
Vesting of share-based compensation	0	4	(4)	0	0
Issuance pursuant to acquisitions	157,405	55	157,350	0	0
Amortization of share-based compensation	5,329	0	5,329	0	0
Net Income (Loss)	$ 340,437	0	0	0	340,437
Shares issued from stock option exercises	15,584
Purchase of treasury shares (shares)	120,350
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment	41,375
Vesting of share-based compensation	375,745
Issuance pursuant to acquisitions	5,448,961
Beginning Balance	$ 791,579	$ 227	$ 576,118	$ (7,534)	$ 222,768

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities:
Net Income (Loss)	$ 340,437	$ 86,759
Adjustments to reconcile net income to net cash provided by operation activities -
Depreciation, depletion, and amortization	133,982	68,629
Accretion of asset retirement obligation	534	306
Deferred income taxes	9,625	6,212
Stock-based compensation expense	5,086	4,645
Gain (Loss) on Sale of Derivatives	73,885	123,018
Cash Received (Paid) On Settlements of Derivative Contracts	(219,626)	(70,582)
Asset Retirement Obligation, Cash Paid to Settle	(48)	(158)
Write off of Deferred Debt Issuance Cost	350	229
Other Noncash Income (Expense)	3,010	2,877
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other assets	(29,522)	(23,513)
Increase (decrease) in accounts payable and accrued liabilities	11,788	17,507
Increase (decrease) in income taxes payable	229	(83)
Increase (decrease) in accrued interest	1,969	(286)
Net Cash Provided by Operating Activities	331,241	215,726
Cash Flows from Investing Activities:
Additions to property and equipment	(272,443)	(133,638)
Acquisition of properties	(367,024)	(51,734)
Proceeds from Sale of Property, Plant, and Equipment	(4,347)	0
Payments for (Proceeds from) Other Investing Activities	(750)	(1,084)
Net Cash Used in Investing Activities	(635,870)	(186,456)
Cash Flows from Financing Activities:
Payments of long-term debt	0	(50,000)
Proceeds from bank borrowings	841,000	335,000
Payments of bank borrowings	(526,000)	(338,000)
Proceeds from Issuance or Sale of Equity	0	26,956
Proceeds from Stock Options Exercised	39	0
Purchase of treasury shares	(3,397)	(612)
Payments of debt issuance costs	(7,342)	(3,611)
Net Cash Provided by (Used in) Financing Activities	304,300	(30,267)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	(329)	(997)
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	792	1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	36,994	27,221
Increase (decrease) in accrued payables for capital	54,372	(4,033)
Other Significant Noncash Transaction, Value of Consideration Given	$ (156,252)	$ (83,522)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
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. Stockholder Rights Agreement . On September 20, 2022, the Board adopted a stockholder rights agreement, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (the “Rights Agreement”), and declared a dividend distribution of one right (each, a “Right” and together with all such rights distributed or issued pursuant to the Rights Agreement, the “Rights”) for each outstanding share of Company common stock to holders of record on October 5, 2022. In the event that a person or group acquires beneficial ownership of 15% or more of the Company’s then-outstanding common stock, subject to certain exceptions, each Right would entitle its holder (other than such person or members of such group) to purchase additional shares of Company common stock at a substantial discount to the public market price. In addition, at any time after a person or group acquires beneficial ownership of 15% or more of the outstanding common stock, subject to certain exceptions, the Board may direct the Company to exchange the Rights (other than Rights owned by such person or certain related parties, which will have become null and void), in whole or in part, at an exchange ratio of one share of common stock per Right (subject to adjustment). While in effect, the Rights Agreement could make it more difficult for a third party to acquire control of the Company or a large block of the common stock of the Company without the approval of the Board. The Rights Agreement will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2023 annual stockholders’ meeting, (b) 5:00 p.m., New York City time, on June 30, 2023, (c) the time at which the Rights are redeemed and (d) the time at which the Rights are exchanged in full. Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. Through February 24, 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, 2022: Natural Gas Basis Derivative Swaps Total Volumes Weighted Average Price Calendar Monthly Roll Differential Swaps 2023 Contracts 1Q23 1,460,000 $ (0.37) 2Q23 1,820,000 $ (0.37) 3Q23 1,840,000 $ (0.27) 4Q23 920,000 $ (0.38) 2024 Contracts 1Q24 1,820,000 $ (0.14) 2Q24 1,820,000 $ (0.35) 3Q24 1,840,000 $ (0.29) 4Q24 1,840,000 $ (0.51) 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, 2022 and 2021, such internal costs when capitalized totaled $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2022 and 2021. 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 $ 2,506,853 $ 1,588,978 Unproved oil and gas properties 16,272 17,090 Furniture, fixtures, and other equipment 6,098 5,885 Less – Accumulated depreciation, depletion, amortization & impairment (1,004,044) (869,985) Property and Equipment, Net $ 1,525,179 $ 741,968 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 business combinations 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 either of the years ended December 31, 2022 and 2021. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash 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 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, 2022 and 2021 (in thousands): Year Ended December 31, 2022 Year Ended December 31, 2021 Oil, natural gas and NGLs sales: Oil $ 239,247 $ 98,607 Natural gas 451,863 267,687 NGLs 62,310 40,906 Total $ 753,420 $ 407,200 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, 2022 and 2021, 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, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million due from joint interest owners, $4.3 million for severance tax credit receivables and $8.9 million for other receivables. At December 31, 2021, our “Accounts receivable, net” balance included $45.3 million for oil and gas sales, $1.9 million for joint interest owners, $1.0 million for severance tax credit receivables and $1.5 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, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $8.8 million and $5.1 million for the years ended December 31, 2022 and 2021, 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, 2022, 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. 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. We continually monitor all positive and negative evidence related to our determination on the need for a valuation allowance. During the fourth quarter of 2022, the Company's overall deferred tax position moved from a net deferred tax asset position into a net deferred tax liability position, exclusive of a valuation allowance. In addition, the Company now believes it has a significant history of earnings over the prior three years and also considered the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods) and projected future taxable income in making this assessment. As such, during the fourth quarter of 2022, the Company's management determined there was sufficient positive evidence that indicated the Company would more likely that not be able to fully utilize its deferred tax assets and as a result, removed the full valuation allowance. Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance. We recorded an income tax provision of $9.6 million which was primarily attributable to deferred federal and state income tax expense of $75.8 million on income before taxes of $350.0 million, $1.4 million of non-deductible expenses, partially offset by a benefit for the release of the $67.6 million valuation allowance, offset by a benefit for the release of the valuation allowance for the year ended December 31, 2022. While the Company expects to realize the deferred tax assets, changes in future taxable income or in tax laws may alter this expectation and result in future increases to the valuation allowance. 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 $ 23,660 $ 9,688 Accrued operating expenses 10,572 4,192 Accrued compensation costs 4,814 7,029 Asset retirement obligations – current portion 1,284 524 Accrued non-income based taxes 4,849 3,314 Accrued corporate and legal fees 1,988 1,972 Other payables (1) 13,033 8,315 Total accounts payable and accrued liabilities $ 60,200 $ 35,034 (1) Included in Other Payables is $6.0 million and $6.4 million in payables for settled derivatives for the years ended December 31, 2022 and 2021, respectively. Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. 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, 2022 and 2021, 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, 2022 Year Ended December 31, 2021 Kinder Morgan 22 % 26 % Plains Marketing 11 % 10 % Twin Eagle * 15 % Trafigura US 14 % 16 % Shell Trading 12 % 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, 2022 and 2021, we purchased 120,350 and 74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous acquisition. New Accounting Pronouncements . In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13 , Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s 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. There were no shares of common stock sold under the ATM Program during the year ended December 31, 2022.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2022
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. 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, 2022 Year Ended December 31, 2021 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 340,437 19,748 $ 17.24 $ 86,759 13,118 $ 6.61 Dilutive Securities: Restricted Stock Unit Awards 162 285 Performance Based Stock Unit Awards 149 117 Stock Option Awards 38 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 340,437 20,097 $ 16.94 $ 86,759 13,520 $ 6.42 Less than 0.1 million and 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the years ended December 31, 2022 and 2021, because they were antidilutive. Less than 0.1 million shares of restricted stock units were not included in the computation of Diluted EPS for the year ended December 31, 2022 because they were antidilutive. There were no antidilutive shares of restricted stock units for the year ended December 31, 2021. There were no antidilutive shares of performance-based restricted stock units for either of the years ended December 31, 2022 and 2021.

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2022
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, 2022 Year Ended December 31, 2021 Income (Loss) Before Income Taxes $ 350,037 $ 93,157 The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2022 Year Ended December 31, 2021 Current: Federal $ — $ — State (25) 186 Total current income tax provision (benefit) (25) 186 Deferred: Federal 7,188 5,500 State 2,437 712 Total deferred income tax provision (benefit) $ 9,625 $ 6,212 Total tax expenses $ 9,600 $ 6,398 Our effective tax rate for 2022 differs from the statutory rate primarily due to the removal of the full valuation allowance during the fourth quarter of 2022. 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, 2022 Year Ended December 31, 2021 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.7 % 1.0 % Executive compensation limitation 0.4 % 0.6 % Other, net (0.1) % 0.6 % Valuation allowance adjustments (19.3) % (16.2) % Effective rate 2.7 % 6.9 % The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2022 and 2021 were as follows (in thousands): December 31, 2022 December 31, 2021 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 130,296 $ 97,142 Other carryover items 649 642 Asset retirement obligations 2,258 1,306 Share-based compensation 439 579 Lease liability 2,589 3,425 Interest 8,798 — Derivative contracts — 11,451 Other 963 2,111 Valuation allowance — (67,578) Total deferred tax assets $ 145,992 $ 49,078 Deferred tax liabilities: Oil and gas exploration and development costs $ (141,771) $ (52,219) Derivative contracts (16,943) — Leased assets (2,536) (3,374) Other (883) (1) Total deferred tax liabilities (162,133) (55,594) Net deferred tax asset (liabilities) $ (16,141) $ (6,516) State net deferred tax liabilities $ (3,453) $ (1,016) Federal net deferred tax liabilities (12,688) (5,500) Net deferred tax asset (liabilities) $ (16,141) $ (6,516) The Company’s valuation allowance balance was $67.6 million at December 31, 2021. There was no valuation allowance at December 31, 2022. 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 $346.2 million generated from 2018 through 2022. The losses generated between 2013 and 2017 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2022 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. We experienced an ownership change within the meaning of Section 382 during 2022 and our annual usage of losses up to the change date in 2022 may be limited; however, at this time, we do no expect any of the losses to expire unused. We generated approximately $151.0 million in NOL carryforward assets in 2022, of which, $53.4 million relates to the time period post ownership change within the meaning of Section 382 and is not subject to limitation. Should we experience another ownership change within the meaning of Section 382, our NOLs could be further limited.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company's long-term debt consisted of the following (in thousands): December 31, 2022 December 31, 2021 Credit Facility Borrowings due 2026 (1) $ 542,000 $ 227,000 Second Lien Notes due 2026 150,000 150,000 692,000 377,000 Unamortized discount on Second Lien Notes (882) (1,061) Unamortized debt issuance cost on Second Lien Notes (2,587) (3,114) Total Long-Term Debt $ 688,531 $ 372,825 (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, 2022 and 2021, we had $8.7 million and $3.6 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $542.0 million and $227.0 million as of December 31, 2022 and 2021, 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 an unscheduled redetermination of the borrowing base requested by SilverBow along with its administrative agent as part of the SandPoint (as defined later) and Sundance asset acquisitions in the second quarter of 2022, the Company entered into the Tenth Amendment to the Credit Facility, effective June 22, 2022 (the “Tenth Amendment”), which among other things, increased the borrowing base under the Credit Facility to $775.0 million from $525.0 million, effective upon the closing of the Sundance acquisition on June 30, 2022; extended the maturity date for the Credit Agreement to October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes); increased the maximum credit amounts from $1.0 billion to $2.0 billion; decreased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; decreased the mortgage coverage and title requirements from 90% to 85%; amended the restricted payment basket allowing the Company to make dividends or other distribution or return of capital to the extent that the Company's total leverage does not exceed 1.25x and the utilization percentage as of the date of such dividend or distribution is less than 80% after giving effect to such restricted payment; and added two new lenders as parties to the Credit Agreement. Earlier in the second quarter of 2022, the Company entered into the Ninth Amendment to the Credit Facility, effective April 12, 2022, as part of the regular, semi-annual redetermination. Prior to the Tenth Amendment, the Ninth Amendment had previously, among other things, increased the borrowing base under the Credit Agreement from $460 million to $525 million. In conjunction with its regularly scheduled semi-annual redetermination, the Company reaffirmed the borrowing base and elected commitment amount under the Credit Facility at $775.0 million, effective November 22, 2022. Effective upon the execution of the Tenth Amendment on June 22, 2022, the Credit Facility matures October 19, 2026 (or to the extent earlier, the date that is 91 days prior to the scheduled maturity of the Company's Second Lien notes), and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $775.0 million. 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, 2022 and 2021. 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 upon the execution of the Tenth Amendment on June 22, 2022, the applicable margin decreased by 50 basis points and ranged from 1.75% to 2.75% based on borrowing base utilization for ABR Loans and 2.75% to 3.75% based on borrowing base utilization 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. As of December 31, 2022, the Company's weighted average interest rate on Credit Facility borrowings was 7.60%. 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 85% of estimated proved reserves of the Company and its subsidiary effective upon the execution of the Tenth Amendment on June 22, 2022. 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 3.00 to 1.0 as of the last day of each fiscal quarter; 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, 2022, 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 $26.9 million and $11.3 million for the years ended December 31, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $1.2 million and $0.5 million for the years ended December 31, 2022 and 2021, 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 at 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 3.25 to 1.0 as of the last day of each fiscal quarter. As of December 31, 2022, 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, 2022, net amounts recorded for the Second Lien Notes were $146.5 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $15.0 million and $17.8 million for the years ended December 31, 2022 and 2021, 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. During the years ended December 31, 2022 and 2021, the Company capitalized $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility. Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2022 and 2021, respectively, related to changes under our Credit Facility.

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	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. During the years ended December 31, 2022 and 2021, the Company recorded losses of $78.0 million and $123.0 million, respectively, relating to our commodity derivative activities. The Company made net cash payments of $219.6 million and $70.6 million for settled derivative contracts during the years ended December 31, 2022 and 2021, respectively. During the year ended December 31, 2022, the Company recorded gains of $4.1 million related to valuation changes on the 2021 and 2022 WTI (“West Texas Intermediate”) Contingency Payouts. At December 31, 2022 and 2021, we had $6.9 million and $0.9 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 2023 and 2022, respectively. At December 31, 2022 and 2021, we also had $6.0 million and $6.4 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 2023 and 2022, 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, 2022 there was $52.5 million and $24.2 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $40.8 million and $7.7 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2021, the Company had $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. 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 $28.2 million net fair value asset at December 31, 2022 and $53.0 million net fair value liability at December 31, 2021. 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, 2022. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 532,175 $ 81.52 2Q23 494,575 $ 80.75 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 249,500 $ 80.47 3Q24 229,000 $ 78.90 4Q24 217,000 $ 77.76 Collar Contracts 2023 Contracts 1Q23 171,707 $ 47.37 $ 66.00 2Q23 167,949 $ 53.91 $ 64.89 3Q23 72,847 $ 59.27 $ 66.26 4Q23 72,242 $ 58.54 $ 65.13 2024 Contracts 1Q24 137,700 $ 51.61 $ 65.86 2Q24 33,000 $ 45.00 $ 60.72 3-Way Collar Contracts 2023 Contracts 1Q23 14,470 $ 44.24 $ 55.14 $ 64.55 2Q23 13,260 $ 44.19 $ 55.04 $ 64.53 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 981,000 $ 6.74 2Q23 3,816,000 $ 4.55 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 1Q23 13,967,900 $ 3.86 $ 5.50 2Q23 12,141,250 $ 3.28 $ 4.05 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 3-Way Collar Contracts 2023 Contracts 1Q23 347,800 $ 2.06 $ 2.56 $ 3.03 2Q23 310,400 $ 2.04 $ 2.54 $ 3.01 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2023 Contracts 1Q23 12,600,000 $ 0.05 2Q23 12,740,000 $ (0.23) 3Q23 12,880,000 $ (0.20) 4Q23 12,880,000 $ (0.22) 2024 Contracts 1Q24 6,370,000 $ 0.03 2Q24 6,370,000 $ (0.31) 3Q24 6,440,000 $ (0.27) 4Q24 6,440,000 $ (0.24) Houston Ship Channel Fixed Price Contracts 2023 Contracts 1Q23 180,000 $ 2.64 2Q23 60,000 $ 2.64 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 1Q23 337,500 $ 33.12 2Q23 341,250 $ 33.12 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $2.0 million for 2023, $1.0 million for 2024, $0.8 million for 2025, $0.7 million for 2026 and $8.9 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, 2022. 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 $1.5 million for the year ended December 31, 2022. Additionally, we have drilling commitments amounting to $8.0 million for 2023, $4.8 million for 2024 and $2.9 million for 2025. 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, 2022
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 $5.1 million and $4.6 million for the years ended December 31, 2022 and 2021, respectively. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2022 and 2021. 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 140,446 at December 31, 2022. 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, 2022, we had no unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the year ended December 31, 2022: Shares Wtd. Avg. Options outstanding, beginning of period 276,009 $ 28.12 Options exercised (15,584) $ 26.96 Options expired (64,263) $ 33.48 Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46 Our outstanding stock option awards at December 31, 2022 had $0.4 million measurable aggregate intrinsic value. At December 31, 2022 the weighted-average remaining contract life of stock option awards outstanding was 4.4 years and exercisable was 4.4 years. The stock option awards exercisable as of December 31, 2022 had $0.4 million in 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, 2022, we had unrecognized compensation expense of $2.8 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.1 years. The following table provides information regarding restricted stock unit activity for the year ended December 31, 2022: Shares Wtd. Avg. Restricted units outstanding, beginning of period 344,845 $ 8.60 Restricted stock units granted 179,416 $ 26.00 Restricted stock units forfeited (19,214) $ 18.55 Restricted stock units vested (277,933) $ 8.86 Restricted stock units outstanding, end of period 227,114 $ 21.18 Performance-Based Stock Units On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 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 On February 23, 2022, the Company granted 122,111 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, 2022 to December 31, 2024. 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 $36.47 per unit or 150.93% 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 As of December 31, 2022, we had unrecognized compensation expense of $3.1 million related to our performance-based stock units based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 2.0 years. The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2022: Shares Wtd. Avg. Performance based stock units outstanding, beginning of period 244,989 $ 18.84 Performance based stock units granted 122,111 $ 36.47 Performance based stock units incremental shares granted 14,212 $ 18.86 Performance based stock units vested (97,812) $ 18.86 Performance based stock units outstanding, end of period 283,500 $ 23.18 Employee Savings Plan

Leases Leases (Notes)

Leases Leases (Notes)	12 Months Ended
	Dec. 31, 2022
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. The Company elected for 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, 2022 Year Ended December 31, 2021 Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 15,219 $ 3,472 Property and equipment acquisitions - operating leases — — Total lease costs in property, plant and equipment additions $ 15,219 $ 3,472 Year Ended December 31, 2022 Year Ended December 31, 2021 Lease Costs Included in the Consolidated Statements of Operations Lease operating costs - short-term leases $ 6,275 $ 1,873 Lease operating costs - operating leases 8,304 5,325 General and administrative, net - operating leases 754 844 Total lease cost expensed $ 15,333 $ 8,042 The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2022 As of December 31, 2021 Weighted-average remaining lease term (in years) 2.5 3.0 Weighted-average discount rate 4.6 % 4.1 % As of December 31, 2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2022 2023 $ 8,939 2024 1,913 2025 934 2026 779 2027 51 Thereafter 488 Total undiscounted lease payments $ 13,104 Present value adjustment (776) Net operating lease liabilities $ 12,328 Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2022 Year Ended December 31, 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 9,052 $ 6,011 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 5,342 $ 8,779 Rental and lease expense was $14.6 million and $7.0 million for the years ended December 31, 2022 and 2021, 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, 2022
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, $0.8 million and $1.1 million was paid during the years ended December 31, 2022 and 2021, respectively. There is no remaining obligation under this contract as of December 31, 2022. 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. 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 part of the post-closing settlement of this acquisition, during the year ended December 31, 2022 we issued 489 new shares and received 41,375 shares back into treasury stock. November 2021 Acquisition On November 19, 2021, the Company closed on an acquisition of oil-weighted assets in the Eagle Ford. 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 (the “2021 WTI Contingency Payout”). During the year ended December 31, 2022, the Company recorded losses of $1.2 million, related to the 2021 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the consolidated statements of operation and recorded $1.6 million in earn-out consideration payable to the seller related to the 2022 calendar year in “Accounts payable and accrued liabilities” on the consolidated balance sheets. 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. 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. May 2022 Acquisition On May 10, 2022, the Company closed the acquisition of certain oil and gas assets located in La Salle and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from SandPoint Operating, LLC, a subsidiary of SandPoint Resources, LLC (collectively, “SandPoint”). After consideration of closing adjustments, total aggregate consideration was approximately $67.5 million, consisting of $27.7 million in cash and 1,300,000 shares of our common stock valued at approximately $39.8 million based on the Company's share price on the closing date. We incurred approximately $0.5 million in transaction costs during the year ended December 31, 2022 related to the acquisition. 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. 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 $ 27,709 Equity consideration 39,767 Total Consideration 67,476 Transaction costs 466 Total Cost of Transaction $ 67,942 Allocation of Total Cost Assets Oil and gas properties $ 84,810 Total assets 84,810 Liabilities Accounts payable and accrued liabilities 199 Fair value of commodity derivatives 16,511 Asset retirement obligations 158 Total Liabilities $ 16,868 Net Assets Acquired $ 67,942 June 2022 Acquisition On June 30, 2022, the Company closed the acquisition of certain oil and gas assets located in Atascosa, La Salle, Live Oak and McMullen Counties, Texas, as well as assumed the seller's commodity derivative contracts in place at the closing date, from Sundance Energy, Inc., and its affiliated entities Armadillo E&P, Inc. and SEA Eagle Ford, LLC (collectively, “Sundance”). After consideration of closing adjustments, total aggregate consideration was approximately $344.9 million, consisting of $220.9 million in cash, 4,148,472 shares of our common stock valued at approximately $117.7 million based on the Company's share price on the closing date, accrued purchase price adjustments receivable of $1.0 million and contingent consideration with an estimated fair value of $7.4 million. The contingent consideration consists of up to two earn-out payments of $7.5 million each, contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil exceeding $95 per barrel for the period from April 13, 2022 through December 31, 2022 which would trigger a payment of $7.5 million in 2023 and $85 per barrel for 2023 which would trigger a payment of $7.5 million in 2024 (the “2022 WTI Contingency Payout”). The contingent payout for the period of April 13, 2022 through December 31, 2022 did not materialize. During the year ended December 31, 2022, the Company recorded gains of $5.3 million related to the 2022 WTI Contingency Payout recorded in “Gain (loss) on commodity derivatives, net” on the accompanying consolidated statements of operations. 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 $6.8 million in transaction costs during the year ended December 31, 2022 related to the acquisition. 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. 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 $ 220,866 Equity consideration 117,651 Fair value of contingent consideration 7,422 Accrued purchase price adjustments receivable (1,000) Total Consideration 344,939 Transaction costs 6,766 Total Cost of Transaction $ 351,705 Allocation of Total Cost Assets Other current assets $ 4,202 Oil and gas properties 397,401 Right of use assets 890 Total assets 402,493 Liabilities Accounts payable and accrued liabilities 13,687 Fair value of commodity derivatives 33,767 Non-current lease liability 890 Asset retirement obligations 2,444 Total Liabilities $ 50,788 Net Assets Acquired $ 351,705 August 2022 Acquisition On August 15, 2022, the Company closed the acquisition of certain oil and gas assets in Webb County, Texas. After consideration of closing adjustments, total consideration was approximately $31.2 million. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. 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. October 2022 Acquisition On October 31, 2022, the Company closed the acquisition of certain oil and gas assets in Dewitt and Gonzales Counties, Texas. After consideration of closing adjustments, total consideration was approximately $80.1 million. The acquisition is subject to further customary post-closing adjustments. We did not incur any significant transaction costs during the year ended December 31, 2022 related to the acquisition. 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. 2022 Non-strategic Dispositions During 2022, the Company closed on multiple dispositions of non-strategic oil and gas assets. After consideration of closing adjustments, total proceeds from the dispositions were approximately $4.3 million. There was no gain or loss recognized in connection with the dispositions.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
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 current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “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 (collectively “Debt Facilities”) 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. 2022 and 2021 Acquisitions . The Company recognized the assets acquired in our 2022 and 2021 acquisitions at cost on 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 and income taxes 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: Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. The following table presents our assets and liabilities that are measured on a recurring basis as of December 31, 2022 and 2021, 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, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 — 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 — 2021 WTI Contingency Payout 1,841 — 1,841 — 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, 2022
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. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying consolidated balance sheets. The following provides a roll-forward of our asset retirement obligations (in thousands): 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 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456 At December 31, 2022 and 2021, approximately $1.3 million and $0.5 million, respectively, 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, 2022
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, 2022 and 2021, such internal costs when capitalized totaled $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for both the years ended December 31, 2022 and 2021. 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 $ 2,506,853 $ 1,588,978 Unproved oil and gas properties 16,272 17,090 Furniture, fixtures, and other equipment 6,098 5,885 Less – Accumulated depreciation, depletion, amortization & impairment (1,004,044) (869,985) Property and Equipment, Net $ 1,525,179 $ 741,968 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 business combinations 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 either of the years ended December 31, 2022 and 2021. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash 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
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, 2022 and 2021, 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, 2022, 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. 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. We continually monitor all positive and negative evidence related to our determination on the need for a valuation allowance. During the fourth quarter of 2022, the Company's overall deferred tax position moved from a net deferred
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 $ 23,660 $ 9,688 Accrued operating expenses 10,572 4,192 Accrued compensation costs 4,814 7,029 Asset retirement obligations – current portion 1,284 524 Accrued non-income based taxes 4,849 3,314 Accrued corporate and legal fees 1,988 1,972 Other payables (1) 13,033 8,315 Total accounts payable and accrued liabilities $ 60,200 $ 35,034 (1) Included in Other Payables is $6.0 million and $6.4 million in payables for settled derivatives for the years ended December 31, 2022 and 2021, 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.
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, 2022 and 2021, we purchased 120,350 and 74,586 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. Additionally, for the year ended December 31, 2022, we received 41,375 shares in conjunction with our post-closing settlement for a previous acquisition.
New Accounting Pronouncements	New Accounting Pronouncements . In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13 , Credit Losses - Measurement of Credit Losses on Financial Instruments. The standard changes how entities will measure credit losses for most financial assets, including accounts and notes receivables. The new standard replaces the existing incurred loss impairment methodology with a methodology that requires consideration of a broader range of reasonable and supportable forward-looking information to estimate all expected credit losses. The updated guidance is effective for the Company for annual and quarterly reporting periods beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures. In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021. The guidance provides and clarifies optional expedients and exceptions for applying generally accepted accounting principles to contract modifications, subject to meeting certain criteria, that reference LIBOR or another reference rate expected to be discontinued. The amendments within these ASUs were in effect beginning March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2024. As of December 31, 2022, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The guidance simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, the amendment requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS). The guidance is effective for the Company for fiscal years beginning after December 15, 2022. The adoption of this guidance is not expected to have a material impact on the Company’s financial statements or disclosures.

Earnings Per Share Earning Per

Earnings Per Share Earning Per Share (Policies)	12 Months Ended
	Dec. 31, 2022
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, 2022
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. During the years ended December 31, 2022 and 2021, the Company capitalized $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility. Additionally, the Company wrote-off $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2022 and 2021, respectively, related to changes under our Credit Facility.

Price-Risk Management Price-R_2

Price-Risk Management Price-Risk Management (Policies)	12 Months Ended
	Dec. 31, 2022
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, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $2.0 million for 2023, $1.0 million for 2024, $0.8 million for 2025, $0.7 million for 2026 and $8.9 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, 2022. 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 $1.5 million for the year ended December 31, 2022. Additionally, we have drilling commitments amounting to $8.0 million for 2023, $4.8 million for 2024 and $2.9 million for 2025. 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, 2022
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 $5.1 million and $4.6 million for the years ended December 31, 2022 and 2021, respectively. Capitalized share-based compensation was $0.2 million and for both the years ended December 31, 2022 and 2021. 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 140,446 at December 31, 2022.

Leases Leases (Policies)

Leases Leases (Policies)	12 Months Ended
	Dec. 31, 2022
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. The Company elected for 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, 2022
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 current and long-term 2021 WTI Contingency Payout and 2022 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “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 (collectively “Debt Facilities”) 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. 2022 and 2021 Acquisitions . The Company recognized the assets acquired in our 2022 and 2021 acquisitions at cost on 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 and income taxes 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: Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets. Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources. Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.

Asset Retirement Obligations _2

Asset Retirement Obligations Asset Retirement Obligations (Policies)	12 Months Ended
	Dec. 31, 2022
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. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying consolidated balance sheets.

Summary of Signigicant Accounti

Summary of Signigicant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. Through February 24, 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, 2022: Natural Gas Basis Derivative Swaps Total Volumes Weighted Average Price Calendar Monthly Roll Differential Swaps 2023 Contracts 1Q23 1,460,000 $ (0.37) 2Q23 1,820,000 $ (0.37) 3Q23 1,840,000 $ (0.27) 4Q23 920,000 $ (0.38) 2024 Contracts 1Q24 1,820,000 $ (0.14) 2Q24 1,820,000 $ (0.35) 3Q24 1,840,000 $ (0.29) 4Q24 1,840,000 $ (0.51)
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 $ 2,506,853 $ 1,588,978 Unproved oil and gas properties 16,272 17,090 Furniture, fixtures, and other equipment 6,098 5,885 Less – Accumulated depreciation, depletion, amortization & impairment (1,004,044) (869,985) Property and Equipment, Net $ 1,525,179 $ 741,968
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, 2022 and 2021 (in thousands): Year Ended December 31, 2022 Year Ended December 31, 2021 Oil, natural gas and NGLs sales: Oil $ 239,247 $ 98,607 Natural gas 451,863 267,687 NGLs 62,310 40,906 Total $ 753,420 $ 407,200
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 $ 23,660 $ 9,688 Accrued operating expenses 10,572 4,192 Accrued compensation costs 4,814 7,029 Asset retirement obligations – current portion 1,284 524 Accrued non-income based taxes 4,849 3,314 Accrued corporate and legal fees 1,988 1,972 Other payables (1) 13,033 8,315 Total accounts payable and accrued liabilities $ 60,200 $ 35,034 (1) Included in Other Payables is $6.0 million and $6.4 million in payables for settled derivatives for the years ended December 31, 2022 and 2021, respectively.
Oil and Gas receipts greater than 10%	For the years ended December 31, 2022 and 2021, 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, 2022 Year Ended December 31, 2021 Kinder Morgan 22 % 26 % Plains Marketing 11 % 10 % Twin Eagle * 15 % Trafigura US 14 % 16 % Shell Trading 12 % 12 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Year Ended December 31, 2021 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 340,437 19,748 $ 17.24 $ 86,759 13,118 $ 6.61 Dilutive Securities: Restricted Stock Unit Awards 162 285 Performance Based Stock Unit Awards 149 117 Stock Option Awards 38 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 340,437 20,097 $ 16.94 $ 86,759 13,520 $ 6.42

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Year Ended December 31, 2021 Income (Loss) Before Income Taxes $ 350,037 $ 93,157
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, 2022 Year Ended December 31, 2021 Current: Federal $ — $ — State (25) 186 Total current income tax provision (benefit) (25) 186 Deferred: Federal 7,188 5,500 State 2,437 712 Total deferred income tax provision (benefit) $ 9,625 $ 6,212 Total tax expenses $ 9,600 $ 6,398
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, 2022 Year Ended December 31, 2021 Federal Statutory Rate 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.7 % 1.0 % Executive compensation limitation 0.4 % 0.6 % Other, net (0.1) % 0.6 % Valuation allowance adjustments (19.3) % (16.2) % Effective rate 2.7 % 6.9 %
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, 2022 and 2021 were as follows (in thousands): December 31, 2022 December 31, 2021 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 130,296 $ 97,142 Other carryover items 649 642 Asset retirement obligations 2,258 1,306 Share-based compensation 439 579 Lease liability 2,589 3,425 Interest 8,798 — Derivative contracts — 11,451 Other 963 2,111 Valuation allowance — (67,578) Total deferred tax assets $ 145,992 $ 49,078 Deferred tax liabilities: Oil and gas exploration and development costs $ (141,771) $ (52,219) Derivative contracts (16,943) — Leased assets (2,536) (3,374) Other (883) (1) Total deferred tax liabilities (162,133) (55,594) Net deferred tax asset (liabilities) $ (16,141) $ (6,516) State net deferred tax liabilities $ (3,453) $ (1,016) Federal net deferred tax liabilities (12,688) (5,500) Net deferred tax asset (liabilities) $ (16,141) $ (6,516)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-term debt	The Company's long-term debt consisted of the following (in thousands): December 31, 2022 December 31, 2021 Credit Facility Borrowings due 2026 (1) $ 542,000 $ 227,000 Second Lien Notes due 2026 150,000 150,000 692,000 377,000 Unamortized discount on Second Lien Notes (882) (1,061) Unamortized debt issuance cost on Second Lien Notes (2,587) (3,114) Total Long-Term Debt $ 688,531 $ 372,825 (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, 2022 and 2021, we had $8.7 million and $3.6 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, 2022
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, 2022. Oil Derivative Swaps Total Volumes (Bbls) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 532,175 $ 81.52 2Q23 494,575 $ 80.75 3Q23 533,980 $ 77.36 4Q23 569,300 $ 78.26 2024 Contracts 1Q24 227,500 $ 80.78 2Q24 249,500 $ 80.47 3Q24 229,000 $ 78.90 4Q24 217,000 $ 77.76 Collar Contracts 2023 Contracts 1Q23 171,707 $ 47.37 $ 66.00 2Q23 167,949 $ 53.91 $ 64.89 3Q23 72,847 $ 59.27 $ 66.26 4Q23 72,242 $ 58.54 $ 65.13 2024 Contracts 1Q24 137,700 $ 51.61 $ 65.86 2Q24 33,000 $ 45.00 $ 60.72 3-Way Collar Contracts 2023 Contracts 1Q23 14,470 $ 44.24 $ 55.14 $ 64.55 2Q23 13,260 $ 44.19 $ 55.04 $ 64.53 3Q23 9,570 $ 43.08 $ 53.41 $ 63.33 4Q23 8,970 $ 43.08 $ 53.38 $ 63.35 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Natural Gas Derivative Swaps Total Volumes (MMBtu) Weighted Average Price Weighted Average Collar Sub Floor Price Weighted Average Collar Floor Price Weighted Average Collar Call Price Swap Contracts 2023 Contracts 1Q23 981,000 $ 6.74 2Q23 3,816,000 $ 4.55 3Q23 4,816,000 $ 4.57 4Q23 3,887,000 $ 4.71 2024 Contracts 1Q24 2,711,000 $ 5.15 2Q24 7,800,000 $ 3.95 3Q24 7,820,000 $ 4.03 4Q24 7,820,000 $ 4.35 2025 Contracts 1Q25 900,000 $ 5.01 2Q25 910,000 $ 4.12 3Q25 920,000 $ 4.27 4Q25 920,000 $ 4.70 Collar Contracts 2023 Contracts 1Q23 13,967,900 $ 3.86 $ 5.50 2Q23 12,141,250 $ 3.28 $ 4.05 3Q23 11,896,400 $ 3.43 $ 4.23 4Q23 12,445,000 $ 3.87 $ 4.80 2024 Contracts 1Q24 7,841,000 $ 4.10 $ 6.19 2Q24 2,823,000 $ 4.05 $ 4.91 3Q24 2,958,000 $ 4.00 $ 5.10 4Q24 2,945,000 $ 4.24 $ 5.63 3-Way Collar Contracts 2023 Contracts 1Q23 347,800 $ 2.06 $ 2.56 $ 3.03 2Q23 310,400 $ 2.04 $ 2.54 $ 3.01 3Q23 233,100 $ 2.00 $ 2.50 $ 2.95 4Q23 219,200 $ 2.00 $ 2.50 $ 2.94 2024 Contracts 1Q24 198,000 $ 2.00 $ 2.50 $ 3.37 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes (MMBtu) Weighted Average Price 2023 Contracts 1Q23 12,600,000 $ 0.05 2Q23 12,740,000 $ (0.23) 3Q23 12,880,000 $ (0.20) 4Q23 12,880,000 $ (0.22) 2024 Contracts 1Q24 6,370,000 $ 0.03 2Q24 6,370,000 $ (0.31) 3Q24 6,440,000 $ (0.27) 4Q24 6,440,000 $ (0.24) Houston Ship Channel Fixed Price Contracts 2023 Contracts 1Q23 180,000 $ 2.64 2Q23 60,000 $ 2.64 NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2023 Contracts 1Q23 337,500 $ 33.12 2Q23 341,250 $ 33.12 3Q23 345,000 $ 32.87 4Q23 345,000 $ 32.87 2024 Contracts 1Q24 127,400 $ 29.39 2Q24 127,400 $ 29.39 3Q24 128,800 $ 29.39 4Q24 128,800 $ 29.39

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Stock Option Activity	The following table represents stock option award activity for the year ended December 31, 2022: Shares Wtd. Avg. Options outstanding, beginning of period 276,009 $ 28.12 Options exercised (15,584) $ 26.96 Options expired (64,263) $ 33.48 Options outstanding, end of period 196,162 $ 26.46 Options exercisable, end of period 196,162 $ 26.46
Restricted Stock Units Activity	The following table provides information regarding restricted stock unit activity for the year ended December 31, 2022: Shares Wtd. Avg. Restricted units outstanding, beginning of period 344,845 $ 8.60 Restricted stock units granted 179,416 $ 26.00 Restricted stock units forfeited (19,214) $ 18.55 Restricted stock units vested (277,933) $ 8.86 Restricted stock units outstanding, end of period 227,114 $ 21.18
Performance-Based Stock Units Activity	The following table provides information regarding performance-based stock unit activity for the year ended December 31, 2022: Shares Wtd. Avg. Performance based stock units outstanding, beginning of period 244,989 $ 18.84 Performance based stock units granted 122,111 $ 36.47 Performance based stock units incremental shares granted 14,212 $ 18.86 Performance based stock units vested (97,812) $ 18.86 Performance based stock units outstanding, end of period 283,500 $ 23.18

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 Year Ended December 31, 2021 Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 15,219 $ 3,472 Property and equipment acquisitions - operating leases — — Total lease costs in property, plant and equipment additions $ 15,219 $ 3,472 Year Ended December 31, 2022 Year Ended December 31, 2021 Lease Costs Included in the Consolidated Statements of Operations Lease operating costs - short-term leases $ 6,275 $ 1,873 Lease operating costs - operating leases 8,304 5,325 General and administrative, net - operating leases 754 844 Total lease cost expensed $ 15,333 $ 8,042
Assets and Liabilities, Lessee	The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2022 As of December 31, 2021 Weighted-average remaining lease term (in years) 2.5 3.0 Weighted-average discount rate 4.6 % 4.1 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of December 31, 2022, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2022 2023 $ 8,939 2024 1,913 2025 934 2026 779 2027 51 Thereafter 488 Total undiscounted lease payments $ 13,104 Present value adjustment (776) Net operating lease liabilities $ 12,328
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, 2022 Year Ended December 31, 2021 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 9,052 $ 6,011 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 5,342 $ 8,779

Business Combinations and Asset

Business Combinations and Asset Acquisitions (Tables)	Jun. 30, 2022	May 10, 2022
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 $ 220,866 Equity consideration 117,651 Fair value of contingent consideration 7,422 Accrued purchase price adjustments receivable (1,000) Total Consideration 344,939 Transaction costs 6,766 Total Cost of Transaction $ 351,705 Allocation of Total Cost Assets Other current assets $ 4,202 Oil and gas properties 397,401 Right of use assets 890 Total assets 402,493 Liabilities Accounts payable and accrued liabilities 13,687 Fair value of commodity derivatives 33,767 Non-current lease liability 890 Asset retirement obligations 2,444 Total Liabilities $ 50,788 Net Assets Acquired $ 351,705	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 $ 27,709 Equity consideration 39,767 Total Consideration 67,476 Transaction costs 466 Total Cost of Transaction $ 67,942 Allocation of Total Cost Assets Oil and gas properties $ 84,810 Total assets 84,810 Liabilities Accounts payable and accrued liabilities 199 Fair value of commodity derivatives 16,511 Asset retirement obligations 158 Total Liabilities $ 16,868 Net Assets Acquired $ 67,942

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021, 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, 2022 Assets Natural Gas Derivatives $ 25,960 $ — $ 25,960 $ — Natural Gas Basis Derivatives 26,023 — 26,023 — Oil Derivatives 14,604 — 14,604 — NGL Derivatives 10,134 — 10,134 — Liabilities Natural Gas Derivatives 28,579 — 28,579 — Natural Gas Basis Derivatives 409 — 409 — Oil Derivatives 19,442 — 19,442 — NGL Derivatives 104 — 104 — 2022 WTI Contingency Payout 2,135 — 2,135 — 2021 WTI Contingency Payout 1,453 — 1,453 — 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 — 2021 WTI Contingency Payout 1,841 — 1,841 —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
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, 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 Accretion expense 534 Liabilities incurred for new wells, acquired wells and facilities construction 3,032 Reductions due to sold wells and facilities (57) Reductions due to plugged wells and facilities (22) Revisions in estimates 919 Asset Retirement Obligations as of December 31, 2022 $ 10,456

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MMBTU $ / MMBTU	Dec. 31, 2021 USD ($)	Feb. 24, 2023 MMBTU $ / MMBTU
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 753,420	$ 407,200
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	2,506,853	1,588,978
Unproved oil and gas properties	16,272	17,090
Furniture, fixtures, and other equipment	6,098	5,885
Less - Accumulated depreciation, depletion, and amortization	(1,004,044)	(869,985)
Property, Plant and Equipment, Net	1,525,179	741,968
Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable	23,660	9,688
Accrued operating expenses	10,572	4,192
Accrued payroll costs	4,814	7,029
Asset retirement obligation - current portion	1,284	524
Accrued taxes	4,849	3,314
Accrued Professional Fees, Current	1,988	1,972
Other payables	13,033	8,315
Total accounts payable and accrued liabilities	$ 60,200	$ 35,034
Customer Concentration Risk | Revenue Benchmark | Kinder Morgan Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	22%	26%
Customer Concentration Risk | Revenue Benchmark | Plains Marketing Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	11%	10%
Customer Concentration Risk | Revenue Benchmark | Twin Eagle Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage		15%
Customer Concentration Risk | Revenue Benchmark | Trafigura US
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	14%	16%
Customer Concentration Risk | Revenue Benchmark | Shell Trading Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	12%	12%
Oil sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 239,247	$ 98,607
Natural gas sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	451,863	267,687
NGL sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 62,310	$ 40,906
Other Contract [Member] | Basis Swap [Member] | First Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,600,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.05
Other Contract [Member] | Basis Swap [Member] | Second Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,740,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.23)
Other Contract [Member] | Basis Swap [Member] | Third Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.20)
Other Contract [Member] | Basis Swap [Member] | Fourth Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.22)
Other Contract [Member] | Basis Swap [Member] | First Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.03
Other Contract [Member] | Basis Swap [Member] | Second Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.31)
Other Contract [Member] | Basis Swap [Member] | Third Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.27)
Other Contract [Member] | Basis Swap [Member] | Fourth Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.24)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | First Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,460,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.37)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Second Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.37)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Third Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.27)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Fourth Quarter 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.38)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | First Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.14)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Second Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.35)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Third Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.29)
Other Contract [Member] | Basis Swap [Member] | Subsequent Event | Fourth Quarter 2024
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.51)

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) MMBTU $ / MMBTU shares	Dec. 31, 2021 USD ($) shares	Feb. 24, 2023 MMBTU $ / MMBTU	Sep. 20, 2022	Aug. 13, 2021 USD ($)
Summary of Significant Accounting Policies (Textual) [Abstract]
Stockholders Rights Agreement, Percentage of Common Stock Threshold				15%
Total capitalized internal costs	$ 4,300	$ 4,800
Discount rate for estimated future net revenues from proved properties	10%
Write-down of oil and gas properties	$ 0	0
Revenue from Contract with Customer, Excluding Assessed Tax	753,420	407,200
Allowance for doubtful accounts receivable, current	100	100
Accounts receivable from oil and gas sales	70,900	45,300
Accounts receivable related to joint interest owners	5,600	1,900
Severance tax credit receivables	4,300	1,000
Other receivables	$ 8,900	1,500
Percentage of working interest in wells	100%
Total amount of supervision fees charged to wells	$ 8,800	5,100
Income Tax Expense (Benefit)	9,600	6,398
Deferred Federal, State and Local, Tax Expense (Benefit)	75,800
Income (Loss) Before Income Taxes	350,037	93,157
Non-deductible tax expenses	1,400
Deferred Tax Assets, Valuation Allowance	0	67,578
Payables for Settled Derivatives	$ 6,000	$ 6,400
Treasury Stock, Shares, Acquired | shares	120,350	74,586
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment | shares	41,375
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 2023 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	12,600,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.05
First Quarter 2023 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,460,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.37)
Second Quarter 2023 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	12,740,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.23)
Second Quarter 2023 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.37)
Third Quarter 2023 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.20)
Third Quarter 2023 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.27)
Fourth Quarter 2023 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.22)
Fourth Quarter 2023 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.38)
First Quarter 2024 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.03
First Quarter 2024 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.14)
Second Quarter 2024 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.31)
Second Quarter 2024 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,820,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.35)
Third Quarter 2024 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.27)
Third Quarter 2024 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.29)
Fourth Quarter 2024 | Other Contract [Member] | Basis Swap [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	(0.24)
Fourth Quarter 2024 | Other Contract [Member] | Basis Swap [Member] | Subsequent Event
Summary of Significant Accounting Policies (Textual) [Abstract]
Oil and Gas Production Hedged Volumes | MMBTU			1,840,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU			(0.51)
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	$ 239,247	98,607
Natural gas sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	451,863	267,687
NGL sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 62,310	$ 40,906
Oil and gas receipts | Customer Concentration Risk | Revenue Benchmark
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage	10%

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Basic EPS:
Net Income (Loss)	$ 340,437	$ 86,759
Income, Share Amounts	19,748	13,118
Earnings (Loss) Per Share, Basic	$ 17.24	$ 6.61
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 340,437	$ 86,759
Weighted Average Shares Outstanding - Diluted	20,097	13,520
Earnings (Loss) Per Share, Diluted	$ 16.94	$ 6.42
Restricted Stock Units (RSUs) [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	162	285
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	100	0
Performance Shares [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	149	117
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	0	0
Stock Options [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	38	0
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	100	300

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Summary of income (Loss) from continuing operations before taxes
Income (Loss) Before Income Taxes	$ 350,037	$ 93,157

Consolidated income tax provisi

Consolidated income tax provision (benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Summary of consolidated income tax provision (benefit)
Current Federal Tax Expense (Benefit)	$ 0	$ 0
State and Local Income Tax Expense (Benefit), Continuing Operations	(25)	186
Current income taxes	(25)	186
Deferred Federal Income Tax Expense (Benefit)	7,188	5,500
Deferred State and Local Income Tax Expense (Benefit)	2,437	712
Deferred Income Tax Expense (Benefit)	9,625	6,212
Income tax provision (benefit)	$ 9,600	$ 6,398

Reconciliation of income taxes

Reconciliation of income taxes using federal statutory rate to effective income tax rate (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
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%	21%
State tax provisions (benefits), net of federal benefits	0.70%	1%
Executive compensation limitation	0.40%	0.60%
Other, net	(0.10%)	0.60%
Valuation allowance adjustments	(19.30%)	(16.20%)
Effective rate	2.70%	6.90%

Tax effects of temporary differ

Tax effects of temporary differences representing the net DTA (DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
DTA, Federal net operating losses (NOLs)	$ 130,296	$ 97,142
DTA, Other loss carryforwards	649	642
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	2,258	1,306
DTA, Unrealized share-based compensation	439	579
Deferred Tax Assets, Tax Deferred Expense, Other	2,589	3,425
Deferred Tax Asset, Interest Carryforward	8,798	0
Deferred Tax Assets, Derivative Instruments	0	11,451
DTA, Other	963	2,111
DTA, Valuation Allowance	0	(67,578)
Total deferred tax assets	145,992	49,078
Deferred tax liabilities:
DTL, Oil and gas exploration and development costs	(141,771)	(52,219)
Deferred Tax Liabilities, Derivatives	(16,943)	0
Deferred Tax Liabilities, Leasing Arrangements	(2,536)	(3,374)
DTL, Other	(883)	(1)
Total deferred tax liabilites	162,133	55,594
Net deferred tax liabilities	(16,141)	(6,516)
State deferred tax liabilities, net	(3,453)	(1,016)
Federal deferred tax assets, net	$ (12,688)	$ (5,500)

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Effective income tax rate reconciliation, percent	21%	21%
State tax provisions (benefits), net of federal benefits	0.70%	1%
Executive compensation limitation	0.40%	0.60%
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent	(0.10%)	0.60%
Valuation allowance adjustments	(19.30%)	(16.20%)
Effective Income Tax Rate Reconciliation, Percent	2.70%	6.90%
Deferred Tax Assets, Valuation Allowance	$ 0	$ 67,578
Operating Loss Carryforward, Income Tax Limitation	80%
Tax Year 2015 [Member]
Operating Loss Carryforwards	$ 114,600
Tax Year 2017 [Member]
Operating Loss Carryforwards	159,600
Tax Year 2021
Operating Loss Carryforwards	346,200
Tax Year 2022
Operating Loss Carryforwards	151,000
Operating Loss Carryforward attributable to Section 382 limitation	$ 53,400

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands				12 Months Ended
	Jun. 22, 2022 USD ($)	Nov. 29, 2021 USD ($)	Nov. 12, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Nov. 22, 2022 USD ($)	Apr. 12, 2022 USD ($)	Dec. 15, 2017 USD ($)
Bank Borrowings
Long-Term Debt, excluding current maturities				$ 688,531	$ 372,825
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				41,948	29,129
Payments of Debt Issuance Costs				7,342	3,611
Write off of Deferred Debt Issuance Cost				350	229
Second Lien
Long-term Debt, Gross				692,000	377,000
Payments of long-term debt		$ (50,000)		$ 0	(50,000)
Professional Fees			$ 100
Discount Rate for Estimated Future Net Revenues from Proved Properties				10%
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net				$ (8,700)	(3,600)
New Credit Facility [Member] | Line of Credit [Member]
Bank Borrowings
Long-Term Debt, excluding current maturities				$ 542,000	227,000
Line of Credit, current borrowing base			460,000			$ 775,000	$ 525,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000,000		$ 1,000,000
Line of Credit, Basis Point Decrease	50
Line of Credit, Required Security Interest on Oil and Gas Properties	85%		90%
Total Leverage Limitation for Return of Capital	1.25
Utilization percentage on date of dividend or distribution	0.80
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%
Debt, Weighted Average Interest Rate				7.60%
Line of Credit, Covenant, Debt to EBITDA Ratio, Minimum	3
Line of Credit, Covenant, Current Ratio, Minimum	1
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				$ 26,900	11,300
Commitment fees included in interest expense, net				1,200	500
Payments of Debt Issuance Costs				7,300	3,600
Write off of Deferred Debt Issuance Cost				400	200
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	0.0175
Debt instrument escalating rates for term benchmark loans	0.0275
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	0.0275
Debt instrument escalating rates for term benchmark loans	0.0375
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net				(2,587)	(3,114)
Long-Term Debt, excluding current maturities				150,000	150,000			$ 198,000
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility				15,000	17,800
Second Lien
Long-term Debt, Gross			$ 150,000					200,000
Debt Instrument, Unamortized Discount				(882)	$ (1,061)			$ (2,000)
Additional interest in the event of default			0.020
Second Lien, Required Security Interest on Proved Reserves			90%
Second Lien, Required Security Interest on Oil and Gas Properties			90%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%			9%
Second Lien, Asset Coverage Ratio, Minimum			1.25
Discount Rate for Estimated Future Net Revenues from Proved Properties			10%
Second Lien, Covenant, Debt to EBITDA Ratio, Minimum			3.25
Long-term Debt				$ 146,500
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, 2022 USD ($) MMBTU bbl $ / MMBTU $ / Boe	Dec. 31, 2021 USD ($)
Derivative [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (78,000)	$ (123,000)
Cash Received (Paid) On Settlements of Derivative Contracts | $	(219,626)	(70,582)
Gain (Loss) on WTI Contingency Payout | $	4,100
Receivables for Settled Derivatives | $	6,900	900
Payables for Settled Derivatives | $	6,000	6,400
Derivative, Fair Value, Net | $	28,200	(53,000)
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	52,500	2,800
Other Noncurrent Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	24,200	200
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	40,800	47,500
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 7,700	$ 8,600
Swap [Member] | First Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	532,175
Derivative, Swap Type, Average Fixed Price | $ / Boe	81.52
Swap [Member] | First Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	981,000
Derivative, Swap Type, Average Fixed Price	6.74
Swap [Member] | First Quarter 2023 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	337,500
Derivative, Swap Type, Average Fixed Price	33.12
Swap [Member] | Second Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	494,575
Derivative, Swap Type, Average Fixed Price | $ / Boe	80.75
Swap [Member] | Second Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,816,000
Derivative, Swap Type, Average Fixed Price	4.55
Swap [Member] | Second Quarter 2023 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	341,250
Derivative, Swap Type, Average Fixed Price	33.12
Swap [Member] | Third Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	533,980
Derivative, Swap Type, Average Fixed Price | $ / Boe	77.36
Swap [Member] | Third Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,816,000
Derivative, Swap Type, Average Fixed Price	4.57
Swap [Member] | Third Quarter 2023 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	345,000
Derivative, Swap Type, Average Fixed Price	32.87
Swap [Member] | Fourth Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	569,300
Derivative, Swap Type, Average Fixed Price | $ / Boe	78.26
Swap [Member] | Fourth Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,887,000
Derivative, Swap Type, Average Fixed Price	4.71
Swap [Member] | Fourth Quarter 2023 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	345,000
Derivative, Swap Type, Average Fixed Price	32.87
Swap [Member] | First Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	227,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	80.78
Swap [Member] | First Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,711,000
Derivative, Swap Type, Average Fixed Price	5.15
Swap [Member] | First Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	127,400
Derivative, Swap Type, Average Fixed Price	29.39
Swap [Member] | Second Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	249,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	80.47
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,800,000
Derivative, Swap Type, Average Fixed Price	3.95
Swap [Member] | Second Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	127,400
Derivative, Swap Type, Average Fixed Price	29.39
Swap [Member] | Third Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	229,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	78.90
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Average Fixed Price	4.03
Swap [Member] | Third Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	128,800
Derivative, Swap Type, Average Fixed Price	29.39
Swap [Member] | Fourth Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	217,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	77.76
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,820,000
Derivative, Swap Type, Average Fixed Price	4.35
Swap [Member] | Fourth Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	128,800
Derivative, Swap Type, Average Fixed Price	29.39
Swap [Member] | First Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	900,000
Derivative, Swap Type, Average Fixed Price	5.01
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	910,000
Derivative, Swap Type, Average Fixed Price	4.12
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Swap Type, Average Fixed Price	4.27
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Swap Type, Average Fixed Price	4.70
Collar Contracts [Member] | First Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	171,707
Derivative, Average Floor Price | $ / Boe	47.37
Derivative, Average Cap Price | $ / Boe	66
Collar Contracts [Member] | First Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,967,900
Derivative, Average Floor Price	3.86
Derivative, Average Cap Price	5.50
Collar Contracts [Member] | Second Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	167,949
Derivative, Average Floor Price | $ / Boe	53.91
Derivative, Average Cap Price | $ / Boe	64.89
Collar Contracts [Member] | Second Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,141,250
Derivative, Average Floor Price	3.28
Derivative, Average Cap Price	4.05
Collar Contracts [Member] | Third Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	72,847
Derivative, Average Floor Price | $ / Boe	59.27
Derivative, Average Cap Price | $ / Boe	66.26
Collar Contracts [Member] | Third Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	11,896,400
Derivative, Average Floor Price	3.43
Derivative, Average Cap Price	4.23
Collar Contracts [Member] | Fourth Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	72,242
Derivative, Average Floor Price | $ / Boe	58.54
Derivative, Average Cap Price | $ / Boe	65.13
Collar Contracts [Member] | Fourth Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,445,000
Derivative, Average Floor Price	3.87
Derivative, Average Cap Price	4.80
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	137,700
Derivative, Average Floor Price | $ / Boe	51.61
Derivative, Average Cap Price | $ / Boe	65.86
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,841,000
Derivative, Average Floor Price	4.10
Derivative, Average Cap Price	6.19
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	33,000
Derivative, Average Floor Price | $ / Boe	45
Derivative, Average Cap Price | $ / Boe	60.72
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,823,000
Derivative, Average Floor Price	4.05
Derivative, Average Cap Price	4.91
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,958,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.10
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	2,945,000
Derivative, Average Floor Price	4.24
Derivative, Average Cap Price	5.63
3-Way Collar | First Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,470
Derivative, Average Floor Price	55.14
Derivative, Average Cap Price	64.55
Derivative, Average Sub Floor Price	44.24
3-Way Collar | First Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	347,800
Derivative, Average Floor Price	2.56
Derivative, Average Cap Price	3.03
Derivative, Average Sub Floor Price	2.06
3-Way Collar | Second Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,260
Derivative, Average Floor Price	55.04
Derivative, Average Cap Price	64.53
Derivative, Average Sub Floor Price	44.19
3-Way Collar | Second Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	310,400
Derivative, Average Floor Price	2.54
Derivative, Average Cap Price	3.01
Derivative, Average Sub Floor Price	2.04
3-Way Collar | Third Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,570
Derivative, Average Floor Price	53.41
Derivative, Average Cap Price	63.33
Derivative, Average Sub Floor Price	43.08
3-Way Collar | Third Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	233,100
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	2.95
Derivative, Average Sub Floor Price	2
3-Way Collar | Fourth Quarter 2023 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,970
Derivative, Average Floor Price	53.38
Derivative, Average Cap Price	63.35
Derivative, Average Sub Floor Price	43.08
3-Way Collar | Fourth Quarter 2023 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	219,200
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	2.94
Derivative, Average Sub Floor Price	2
3-Way Collar | First Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	8,247
Derivative, Average Floor Price	57.50
Derivative, Average Cap Price	67.85
Derivative, Average Sub Floor Price	45
3-Way Collar | First Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	198,000
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.37
Derivative, Average Sub Floor Price	2
3-Way Collar | Second Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,757
Derivative, Average Floor Price	57.50
Derivative, Average Cap Price	67.85
Derivative, Average Sub Floor Price	45
3-Way Collar | Second Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	188,000
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.37
Derivative, Average Sub Floor Price	2
Basis Swap [Member] | First Quarter 2023 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,600,000
Derivative, Swap Type, Average Fixed Price	0.05
Basis Swap [Member] | First Quarter 2023 | Houston Ship Channel Fixed Price Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	180,000
Derivative, Swap Type, Average Fixed Price	2.64
Basis Swap [Member] | Second Quarter 2023 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,740,000
Derivative, Swap Type, Average Fixed Price	(0.23)
Basis Swap [Member] | Second Quarter 2023 | Houston Ship Channel Fixed Price Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	60,000
Derivative, Swap Type, Average Fixed Price	2.64
Basis Swap [Member] | Third Quarter 2023 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price	(0.20)
Basis Swap [Member] | Fourth Quarter 2023 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	12,880,000
Derivative, Swap Type, Average Fixed Price	(0.22)
Basis Swap [Member] | First Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price	0.03
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,370,000
Derivative, Swap Type, Average Fixed Price	(0.31)
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price	(0.27)
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	6,440,000
Derivative, Swap Type, Average Fixed Price	(0.24)

Commitments and Contingencies (

Commitments and Contingencies (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Obligations (Textual)
Transportation Expense Incurred	$ 1.5
Gas transportation and processing obligations [Member]
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	2
Contractual Obligation, Due in Second Year	1
Contractual Obligation, Due in Third Year	0.8
Contractual Obligation, Due in Fourth Year	0.7
Contractual Obligation	8.9
Drilling Commitment
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	8
Contractual Obligation, Due in Second Year	4.8
Contractual Obligation, Due in Third Year	$ 2.9

Share-Based Compensation (Detai

Share-Based Compensation (Details 1) - $ / shares				12 Months Ended
	Feb. 23, 2022	Feb. 24, 2021	May 21, 2019	Dec. 31, 2022	Dec. 31, 2021
Share-based Payment Arrangement, Option [Member]
Stock option activity in shares and weighted average price
Options outstanding, beginning of period, shares				276,009
Options outstanding, beginning of period, weighted average price				$ 28.12
Options, exercised in period				(15,584)
Options, Exercises in Period, Weighted Average Exercise Price				$ 26.96
Options expired				(64,263)
Options expired, weighted average price				$ 33.48
Options outstanding, end of period, shares				196,162
Options outstanding, end of period, weighted average price				$ 26.46
Options exercisable, end of period, shares				196,162
Options exercisable, end of period, weighted average price				$ 26.46
Restricted Stock Units (RSUs) [Member]
Restricted stock activity
Restricted units outstanding				227,114	344,845
Restricted units outstanding, weighted average price				$ 21.18	$ 8.60
Restricted stock units granted				179,416
Restricted stock units granted, weighted average price				$ 26
Restricted stock units forfeited				(19,214)
Restricted stock units forfeited, weighted average price				$ 18.55
Restricted stock units vested				(277,933)
Restricted stock units vested, weighted average price				$ 8.86
Performance-based stock unit [Member]
Restricted stock activity
Restricted units outstanding				283,500	244,989
Restricted units outstanding, weighted average price				$ 23.18	$ 18.84
Restricted stock units granted	122,111	161,389	99,500
Restricted stock units granted, weighted average price	$ 36.47	$ 13.13	$ 18.86
Performance based stock units, incremental shares vested	14,212
Performance based stock units, incremental shares vested, weighted average grant date fair value	$ 18.86
Restricted stock units vested	(97,812)			(97,812)
Restricted stock units vested, weighted average price				$ 18.86

Share-Based Compensation (Det_2

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands						12 Months Ended
	Feb. 22, 2023	Feb. 23, 2022	Feb. 24, 2021	Dec. 31, 2020	May 21, 2019	Dec. 31, 2022	Dec. 31, 2021
Stock-Based Compensation Plan
Share-based compensation expenses						$ 5,086	$ 4,645
Share-based Payment Arrangement, Amount Capitalized						$ 200	200
Shares available for future grant under stock compensation plans						140,446
Employee Savings Plan [Abstract]
Employee Savings Plan, Employer Matching Contribution, Percent						100%
Employee Savings Plan, Maximum Annual Contribution Per Employee, Percent						6%
Employee Savings Plan, Employer Discretionary Contribution Amount						$ 600	500
General and Administrative Expense [Member]
Stock-Based Compensation Plan
Share-based compensation expenses						5,100	$ 4,600
Share-based Payment Arrangement, Option [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						0
Outstanding stock options aggregate intrinsic value						$ 400
Remaining contract life of outstanding stock options.						4 years 4 months 24 days
Remaining contract life of exercisable stock option						4 years 4 months 24 days
Intrinsic value of exercised stock option						$ 400
Restricted Stock Units (RSUs) [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						$ 2,800
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards						2 years 1 month 6 days
Restricted units outstanding						227,114	344,845
Restricted stock units granted						179,416
Restricted stock units granted, weighted average price						$ 26
Restricted stock units vested						277,933
Performance-based stock unit [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards						$ 3,100
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards				2 years
Restricted units outstanding						283,500	244,989
Restricted stock units granted		122,111	161,389		99,500
Restricted stock units granted, weighted average price		$ 36.47	$ 13.13		$ 18.86
Percent of payout for performance based stock units		150.93%	157.60%		112.90%	100%
Approved payout for performance based stock units		117%
Restricted stock units vested		97,812				97,812
Performance-based stock unit [Member] | Subsequent Event
Stock Units [Abstract]
Approved payout for performance based stock units	188%
Restricted stock units vested	303,410
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%	0%		0%
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%	200%		200%
Performance Period for Award		3 years			3 years	2 years

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Feb. 05, 2021
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 15,333	$ 8,042
Operating Lease, Weighted Average Remaining Lease Term	2 years 6 months	3 years
Operating Lease, Weighted Average Discount Rate, Percent	4.60%	4.10%
Lessee, Operating Lease, Liability, Payments, Due Year One	$ 8,939
Lessee, Operating Lease, Liability, Payments, Due Year Two	1,913
Lessee, Operating Lease, Liability, Payments, Due Year Three	934
Lessee, Operating Lease, Liability, Payments, Due Year Four	779
Lessee, Operating Lease, Liability, Payments, Due Year Five	51
Lessee, Operating Lease, Liability, Payments, Due after Year Five	488
Lessee, Operating Lease, Liability, Payments, Due	13,104
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(776)
Operating Lease, Liability	12,328
Operating Lease, Payments	9,052	$ 6,011
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	5,342	8,779
Rental expense	14,600	7,000
Building [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due	3,000
Lessee, Operating Lease, Term of Contract			5 years
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	6,275	1,873
Operating Lease, Cost	8,304	5,325
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	754	844
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	15,219	3,472
Operating Lease, Cost	0	0
Lease, Cost	$ 15,219	$ 3,472

Acquisitions and Dispositions (

Acquisitions and Dispositions (Details) $ in Thousands								12 Months Ended
	Oct. 31, 2022 USD ($)	Aug. 15, 2022 USD ($)	Jun. 30, 2022 USD ($) shares	May 10, 2022 USD ($) shares	Nov. 19, 2021 USD ($) shares	Oct. 01, 2021 USD ($) shares	Aug. 03, 2021 USD ($) shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares	Dec. 22, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments for (Proceeds from) Other Investing Activities								$ 750	$ 1,084
Issuance pursuant to acquisitions | shares								5,448,961	3,210,626
Right of use assets								$ 12,077	$ 16,065
Non-current lease liability								3,775	9,090
Asset Retirement Obligations, Noncurrent								9,171	5,526
WTI Contingency Payout					$ 1,900
Gain (Loss) on WTI Contingency Payout								4,100
Derivative, Fair Value, Net								28,200	(53,000)
Other Assets, Current								2,671	1,875
Accounts Payable and Accrued Liabilities, Current								$ 60,200	35,034
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment | shares								41,375
Proceeds from Sale of Property, Plant, and Equipment								$ 4,347	$ 0
La Mesa
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Wells Purchased							12
Asset Acquisition, Consideration Transferred							$ 23,000
Payments to Acquire Oil and Gas Property							$ 13,000
Issuance pursuant to acquisitions | shares							516,675
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable							$ 10,000
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		489
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable						$ 35,600
Asset Acquisition, Transaction Costs								$ 600
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment | shares								41,375
Teal Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred					77,400
Payments to Acquire Oil and Gas Property								$ 37,600
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable					$ 37,900
WTI Annual Earn Out Payment								$ 1,600
WTI Annual Earn Out, Average Monthly Settlement Price								70
Gain (Loss) on WTI Contingency Payout								$ 1,200
2021 WTI Contingency Payable								1,600
Asset Acquisition, Transaction Costs								300
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
SandPoint Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred				$ 67,476
Payments to Acquire Oil and Gas Property				27,709
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable				$ 39,767
Asset Acquisition, Total Cost of Transaction								67,942
Allocation of Total Cost, Oil and gas properties								84,810
Allocation of Total Cost, Total assets								84,810
Asset Retirement Obligations, Noncurrent								158
Allocation of Total Cost, Total Liabilities								16,868
Asset Acquisition, Transaction Costs								466
Derivative, Fair Value, Net								16,511
Accounts Payable and Accrued Liabilities, Current								199
SandPoint 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				1,300,000
Sundance Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred			$ 344,939
Payments to Acquire Oil and Gas Property			220,866
Asset Acquisition, Consideration Transferred, Equity Interest Issued and Issuable			117,651
Asset Acquisition, Total Cost of Transaction			351,705
Allocation of Total Cost, Oil and gas properties			397,401
Right of use assets			890
Allocation of Total Cost, Total assets			402,493
Non-current lease liability			890
Asset Retirement Obligations, Noncurrent			2,444
Allocation of Total Cost, Total Liabilities			50,788
WTI Annual Earn Out Payment			7,500
Gain (Loss) on WTI Contingency Payout								5,300
Asset Acquisition, Transaction Costs			6,766					$ 6,800
Derivative, Fair Value, Net			33,767
Account Receivable for purchase price adjustments			(1,000)
2022 WTI Contingency Payout Fair Value			$ 7,422
WTI Annual Earn Out, Average Monthly Settlement Price 2022			95
2023 WTI Annual Earn Out Payment			$ 7,500
WTI Annual Earn Out, Average Monthly Settlement Price 2023			85
2024 WTI Annual Earn Out Payment			$ 7,500
Other Assets, Current			4,202
Accounts Payable and Accrued Liabilities, Current			$ 13,687
Sundance 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			4,148,472
Arkoma Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred		$ 31,200
Dewitt and Gonzalez Counties Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred	$ 80,100
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

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	$ 25,960	$ 1,159
Derivative Liability	28,579	31,801
Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	26,023	1,025
Derivative Liability	409	452
Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	14,604	371
Derivative Liability	19,442	21,330
2022 WTI Contingency Payout Fair Value	2,135
2021 WTI Contingency Payout Fair Value	1,453	1,841
Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset		3
Derivative Liability		514
NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	10,134	449
Derivative Liability	104	1,941
Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2022 WTI Contingency Payout Fair Value	0
2021 WTI Contingency Payout Fair Value	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset		0
Derivative Liability		0
Fair Value, Inputs, Level 1 [Member] | NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	25,960	1,159
Derivative Liability	28,579	31,801
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	26,023	1,025
Derivative Liability	409	452
Fair Value, Inputs, Level 2 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	14,604	371
Derivative Liability	19,442	21,330
2022 WTI Contingency Payout Fair Value	2,135
2021 WTI Contingency Payout Fair Value	1,453	1,841
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset		3
Derivative Liability		514
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	10,134	449
Derivative Liability	104	1,941
Fair Value, Inputs, Level 3 [Member] | Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2022 WTI Contingency Payout Fair Value	0
2021 WTI Contingency Payout Fair Value	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset		0
Derivative Liability		0
Fair Value, Inputs, Level 3 [Member] | NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	0	0
Derivative Liability	$ 0	$ 0

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 10,456	$ 6,050	$ 4,974
Accretion expense	534	306
Liabilities incurred for new wells and facilities construction	3,032	1,120
Asset Retirement Obligation, Liabilities Settled	(57)
Asset Retirement Obligation, Liabilities Plugged	(22)	(192)
Revisions in estimates	919	(158)
Asset retirement obligation - current portion	$ 1,284	$ 524

Uncategorized Items - sbow-2022

Label	Element	Value
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents	us-gaap_CashCashEquivalentsRestrictedCashAndRestrictedCashEquivalents	$ 2,118,000