SilverBow Resources (SBOW) 10-K 29 Feb 24 2023 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 23, 2024	Jun. 30, 2023
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2023
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			$ 518,174,326
Entity Common Stock, Shares Outstanding		25,429,610
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Filer Category	Accelerated Filer
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Annual Report	true

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Name	BDO USA, P.C.
Auditor Firm ID	243
Auditor Location	Houston, Texas
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 969	$ 792
Accounts receivable	138,343	89,714
Fair value of commodity derivatives	116,549	52,549
Other current assets	5,590	2,671
Total Current Assets	261,451	145,726
Property and Equipment:
Property, Plant and Equipment, Gross	3,597,160	2,529,223
Less - Accumulated depreciation, depletion, and amortization	(1,223,241)	(1,004,044)
Property, Plant and Equipment, Net	2,373,919	1,525,179
Right of use assets	12,888	12,077
Fair value of long-term commodity derivatives	55,114	24,172
Other Long-Term Assets	31,090	9,208
Total Assets	2,734,462	1,716,362
Current Liabilities:
Accounts payable and accrued liabilities	98,816	60,200
Deferred acquisition liability	50,000	0
Fair value of commodity derivatives	5,509	40,796
Accrued capital costs	31,900	56,465
Long-Term Debt, Current Maturities	28,125	0
Accrued interest	9,668	2,665
Current lease liability	4,001	8,553
Undistributed oil and gas revenues	20,425	27,160
Total Current Liabilities	248,444	195,839
Long-Term Debt	1,173,766	688,531
Non-current lease liability	8,899	3,775
Deferred tax liabilities, net	99,227	16,141
Asset Retirement Obligation	11,584	9,171
Fair value of long-term commodity derivatives	2,504	7,738
Other long-term liabilities	$ 710	$ 3,588
Preferred Stock, Shares Outstanding	0	0
Stockholders' Equity:
Preferred Stock, Value, Outstanding	$ 0	$ 0
Common Stock, Value, Issued	259	227
Additional paid-in capital	679,202	576,118
Treasury Stock, Value	(10,617)	(7,534)
Retained earnings (Accumulated deficit)	520,484	222,768
Total Stockholders' Equity (Deficit)	1,189,328	791,579
Total Liabilities and Stockholders' Equity	2,734,462	1,716,362
Capitalized Costs, Unproved Properties	$ 28,375	$ 16,272
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	25,914,956	22,663,135
Common Stock, Shares, Outstanding	25,429,610	22,309,740
Treasury Stock, Shares	485,346	353,395

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Document Period End Date	Dec. 31, 2023
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	40,000,000	40,000,000

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Oil and gas sales	$ 652,358	$ 753,420	$ 407,200
Costs and Expenses:
General and administrative, net	24,520	21,395	21,799
Depreciation, depletion, and amortization	219,116	133,982	68,629
Accretion of asset retirement obligation	985	534	306
Lease operating cost	87,368	55,329	27,206
Workovers	2,694	1,655	514
Transportation and gas processing	59,032	32,989	24,145
Severance and other taxes	38,701	41,761	19,307
Total Operating Expenses	432,416	287,645	161,906
Operating Income (Loss)	219,942	465,775	245,294
Net gain (loss) on commodity derivatives	241,309	(73,885)	(123,018)
Interest expense, net	(80,119)	(41,948)	(29,129)
Other income (expense), net	197	95	10
Income (Loss) Before Income Taxes	381,329	350,037	93,157
Provision (Benefit) for Income Taxes	83,613	9,600	6,398
Net Income (Loss)	$ 297,716	$ 340,437	$ 86,759
Per Share Amounts-
Earnings (Loss) Per Share, Basic	$ 12.74	$ 17.24	$ 6.61
Earnings (Loss) Per Share, Diluted	$ 12.63	$ 16.94	$ 6.42
Weighted Average Shares Outstanding - Basic	23,371	19,748	13,118
Weighted Average Shares Outstanding - Diluted	23,571	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, Common	Retained Earnings (Deficit)
Beginning Balance	$ 91,033	$ 121	$ 297,712	$ (2,372)	$ (204,428)
Purchase of treasury shares	(612)	0	0	(612)	0
Issuance of common stock	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
Issuance of common stock	27,000
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
Purchase of treasury shares	(3,083)	0	0	(3,083)	0
Issuance of common stock	97,309	28	97,281	0	0
Vesting of share-based compensation	0	4	(4)	0	0
Amortization of share-based compensation	5,807	0	5,807	0	0
Net Income (Loss)	$ 297,716	0	0	0	297,716
Purchase of treasury shares (shares)	131,951
Issuance of common stock	2,810,811
Vesting of share-based compensation	441,010
Beginning Balance	$ 1,189,328	$ 259	$ 679,202	$ (10,617)	$ 520,484

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities:
Net Income (Loss)	$ 297,716	$ 340,437	$ 86,759
Adjustments to reconcile net income to net cash provided by operation activities -
Depreciation, depletion, and amortization	219,116	133,982	68,629
Accretion of asset retirement obligation	985	534	306
Deferred income taxes	83,086	9,625	6,212
Stock-based compensation expense	5,526	5,086	4,645
Gain (Loss) on Sale of Derivatives	(241,309)	73,885	123,018
Cash Received (Paid) On Settlements of Derivative Contracts	88,679	(219,626)	(70,582)
Asset Retirement Obligation, Cash Paid to Settle	(716)	(48)	(158)
Write off of Deferred Debt Issuance Cost	1,239	350	229
Other Noncash Income (Expense)	3,528	3,010	2,877
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other assets	(25,439)	(29,522)	(23,513)
Increase (decrease) in accounts payable and accrued liabilities	7,172	11,788	17,507
Increase (decrease) in income taxes payable	(525)	229	(83)
Increase (decrease) in accrued interest	7,003	1,969	(286)
Net Cash Provided by Operating Activities	447,111	331,241	215,726
Cash Flows from Investing Activities:
Additions to property and equipment	(421,273)	(272,443)	(133,638)
Acquisition of properties	(604,955)	(367,024)	(51,734)
Proceeds from Sale of Property, Plant, and Equipment	(713)	(4,347)	0
Payments for (Proceeds from) Other Investing Activities	0	(750)	(1,084)
Net Cash Used in Investing Activities	(1,025,515)	(635,870)	(186,456)
Cash Flows from Financing Activities:
Proceeds from long-term debt	356,965	0	0
Payments of long-term debt	(14,250)	0	(50,000)
Proceeds from bank borrowings	672,000	841,000	335,000
Payments of bank borrowings	(492,000)	(526,000)	(338,000)
Proceeds from Issuance of Common Stock	97,309	0	26,956
Proceeds from Stock Options Exercised	0	39	0
Purchase of treasury shares	(3,083)	(3,397)	(612)
Payments of debt issuance costs	(30,600)	(7,342)	(3,611)
Net Cash Provided by (Used in) Financing Activities	586,341	304,300	(30,267)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Excluding Exchange Rate Effect	7,937	(329)	(997)
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	8,729	792	1,121
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	68,116	36,994	27,221
Increase (decrease) in accrued payables for capital	(13,679)	54,372	(4,033)
Other Significant Noncash Transaction, Value of Consideration Given	0	(156,252)	(83,522)
Non-cash deferred consideration for acquisitions	(50,000)	0	0
Non-cash contingent consideration for acquisitions	$ (16,933)	$ 0	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Recent Events. On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake Energy Corporation, through its wholly owned subsidiaries Chesapeake Exploration, L.L.C., Chesapeake Operating, L.L.C., Chesapeake Energy Marketing, L.L.C. and Chesapeake Royalty, L.L.C. (collectively “Chesapeake”) (the “Chesapeake Transaction”) for total cost of $653.4 million. For further discussion related to this acquisition, refer to Note 9 of these Notes to Consolidated Financial Statements. 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 (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, dated as of September 20, 2022, by and between the Company and American Stock Transfer & Trust Company, LLC, as rights agent, 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. On May 16, 2023, the Company and the rights agent entered into an Amendment to the Rights Agreement (the “Amendment”) that amended the Rights Agreement to extend the expiration date until the close of business on the first day following the date of the Company’s first annual meeting of its stockholders that occurs after (but not on) the date of the Amendment. The Rights Agreement, as amended, will expire on the earliest of (a) 5:00 p.m., New York City time, on the first business day after the 2024 annual stockholders’ meeting, (b) the time at which the Rights are redeemed and (c) 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. There were no material subsequent events requiring additional disclosure in these Notes to Consolidated Financial Statements. 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 oil and gas 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 acquisitions, • 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, 2023, 2022 and 2021, such internal costs when capitalized totaled $5.5 million, $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for the years ended December 31, 2023, 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 $ 3,562,268 $ 2,506,853 Unproved oil and gas properties 28,375 16,272 Furniture, fixtures, and other equipment 6,517 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,223,241) (1,004,044) Property and Equipment, Net $ 2,373,919 $ 1,525,179 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 the years ended December 31, 2023, 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 or timing 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, consistent with contractual terms common in the oil and gas industry. These contracts typically provide for cash settlement within 25 days following each production month. 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. Our oil and gas sales are recognized based on the actual volumes 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, 2023, 2022 and 2021 (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Oil, natural gas and NGLs sales: Oil $ 402,728 $ 239,247 $ 98,607 Natural gas 187,340 451,863 267,687 NGLs 62,291 62,310 40,906 Total $ 652,358 $ 753,420 $ 407,200 Accounts Receivable, Net . We assess the collectibility of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At both December 31, 2023 and 2022, we had an allowance for credit losses of less than $0.1 million. The allowance for credit losses has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets. At December 31, 2023, our “Accounts receivable, net” balance included $91.9 million for oil and gas sales, $7.0 million due from joint interest owners, $7.2 million for severance tax credit receivables, $18.1 million for accrued purchase price adjustments receivable related to the Chesapeake Transaction and $14.2 million for other receivables. At December 31, 2022, our “Accounts receivable, net” balance included $70.9 million for oil and gas sales, $5.6 million for 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, 2023, 2022 and 2021 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $12.5 million, $8.8 million and $5.1 million for the years ended December 31, 2023, 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, 2023, 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. We recorded an income tax provision of $83.6 million, $9.6 million and $6.4 million for the years ended December 31, 2023, 2022 and 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 determined it had 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 $83.6 million which was primarily attributable to deferred federal and current and deferred state income tax expense of $82.9 million on income before taxes of $381.3 million and $0.7 million of non-deductible expenses for the year ended December 31, 2023. 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 $ 32,225 $ 23,660 Accrued operating expenses 23,104 10,572 Accrued compensation costs 10,208 4,814 Asset retirement obligations – current portion 1,576 1,284 Accrued non-income based taxes 3,870 4,849 WTI contingency liability - current portion 14,282 1,600 Accrued corporate and legal fees 208 388 Other payables (1)(2) 13,343 13,033 Total accounts payable and accrued liabilities $ 98,816 $ 60,200 (1) Included in Other Payables is $1.0 million and $6.0 million in payables for settled derivatives for the years ended December 31, 2023 and 2022, respectively. (2) Included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our Chesapeake Transaction for the year ended December 31, 2023. Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. As of December 31, 2023, there was $2.2 million and $5.6 million, in current and long-term restricted cash, respectively. There was no restricted cash as of December 31, 2022. The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet presentation (in thousands): December 31, December 31, Cash and cash equivalents $ 969 $ 792 Current restricted cash (1) 2,200 — Long-term restricted cash (2) 5,560 — Total cash, cash equivalents and restricted cash $ 8,729 $ 792 (1) Current restricted cash is included in “Other Current Assets” on the accompanying consolidated balance sheet. (2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying consolidated balance sheet. 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, 2023, 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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Kinder Morgan 15 % 22 % 26 % Shell Trading 11 % 12 % 12 % Enterprise Products 29 % * * Plains Marketing * 11 % 10 % Trafigura US * 14 % 16 % Twin Eagle * * 15 % *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, 2023, 2022 and 2021, we purchased 131,951, 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. Preferred Stock Purchase Rights. On September 20, 2022, the Board declared a dividend distribution of one preferred stock purchase right (each, a “Right”) for each outstanding share of our common stock. As of and after the Distribution Date (as defined in the Rights Agreement, as amended dated May 16, 2023, between the Company and American Stock Transfer & Trust Company (the “Rights Agreement”) governing the Rights), each right will become exercisable to purchase one one-thousandth of a share of Series B Junior Participating Preferred Stock, par value $0.01 per share (the “Preferred Stock”), at a purchase price of $160.00. This portion of a share of Preferred Stock would give the holder thereof approximately the same dividend, voting, and liquidation rights as would one share of Common Stock. Prior to exercise, the Right does not give its holder any dividend, voting or liquidation rights. The Rights will expire on the earliest of (a) 5:00 p.m., New York City time on the day after the 2024 annual shareholders’ meeting, (b) the time at which the Rights are redeemed (as described in the Rights Agreement), and (c) the time at which the Rights are exchanged in full. 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, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated 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, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. 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. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 4 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's consolidated financial statements or disclosures. 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, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures. In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The guidance aims to improve the effectiveness of income tax disclosures primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard; however, we do not expect it to have a material impact on our disclosures. In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The guidance requires disclosures of certain general information related to the Company's segment. This includes information on the factors used to identify reportable segments, the types of products and services from which report segments generate revenues and whether operating segments have been aggregated. The new requirements will result in incremental disclosures in annual and interim reports. This guidance will apply to fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The new guidance must be applied retrospectively to all prior periods presented in the financial statements unless impracticable with early adoption permitted. We are currently evaluating the impact of this standard. ATM Program. On August 13, 2021, the Company entered into an equity distribution agreement pursuant to which the Company was permitted to 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 used the net proceeds from 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, 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 years ended December 31, 2023 and 2022, and the ATM Program has been terminated.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 297,716 23,371 $ 12.74 $ 340,437 19,748 $ 17.24 $ 86,759 13,118 $ 6.61 Dilutive Securities: Restricted Stock Unit Awards 104 162 285 Performance Based Stock Unit Awards 76 149 117 Stock Option Awards 20 38 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 297,716 23,571 $ 12.63 $ 340,437 20,097 $ 16.94 $ 86,759 13,520 $ 6.42 On September 18, 2023, the Company issued 2,810,811 shares of its common stock in a registered underwritten offering, for aggregate net proceeds, after offering expenses and fees, of approximately $97.3 million. The offering expenses and fees associated with the offering were immaterial. The following is a table of antidilutive options and shares excluded from the computation of Diluted EPS for the periods indicated below (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Antidilutive Securities: Stock Option Awards — 1 286 Restricted Stock Unit Awards 8 5 — Performance Based Stock Unit Awards — — —

Provision (Benefit) for Income

Provision (Benefit) for Income Taxes	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Income (Loss) Before Income Taxes $ 381,329 $ 350,037 $ 93,157 The following is an analysis of the consolidated income tax provision (benefit) (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Current: Federal $ — $ — $ — State 527 (25) 186 Total current income tax provision (benefit) 527 (25) 186 Deferred: Federal 80,634 7,188 5,500 State 2,452 2,437 712 Total deferred income tax provision (benefit) 83,086 9,625 6,212 Total tax provision (benefit) $ 83,613 $ 9,600 $ 6,398 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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Federal Statutory Rate 21.0 % 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.8 % 0.7 % 1.0 % Non-deductible expenses 0.2 % 0.4 % 0.6 % Other, net (0.1) % (0.1) % 0.6 % Valuation allowance adjustments — % (19.3) % (16.2) % Effective rate 21.9 % 2.7 % 6.9 % The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2023 and 2022 were as follows (in thousands): December 31, 2023 December 31, 2022 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 142,694 $ 130,296 Other carryover items 683 649 Asset retirement obligations 2,842 2,258 Share-based compensation 491 439 Lease liability 2,709 2,589 Interest 21,528 8,798 Other 1,253 963 Total deferred tax assets $ 172,200 $ 145,992 Deferred tax liabilities: Oil and gas exploration and development costs $ (232,902) $ (141,771) Derivative contracts (35,336) (16,943) Leased assets (2,707) (2,536) Other (482) (883) Total deferred tax liabilities (271,427) (162,133) Net deferred tax asset (liabilities) $ (99,227) $ (16,141) State net deferred tax liabilities $ (5,905) $ (3,453) Federal net deferred tax liabilities (93,322) (12,688) Net deferred tax asset (liabilities) $ (99,227) $ (16,141) The Company’s NOL carryforward asset is attributable to Federal tax losses of $274.2 million generated from 2013 through 2017 and $405.3 million generated from 2018 through 2023. The losses generated before 2018 will expire between 2033 and 2037 if not utilized. The losses generated from 2018 through 2023 will not expire under the current tax code, but their usage will be limited to 80% of taxable income. In addition, the Company has a net interest expense carryforward of $102.5 million under Section 163(j) of the Code, which will not expire but the usage of which may be limited. 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 not expect any of the losses to expire unused. Should we experience another ownership change within the meaning of Section 382, our NOLs could be further limited. Our U.S. federal and most state income tax returns from 2020 forward are subject to examination. For years prior to 2020 our U.S. federal returns are subject to examination to the extent of our net operating loss (NOL) carryforwards. Our Texas tax returns from 2018 forward are subject to examination. There are no material unresolved items related to periods previously audited by the taxing authorities. On August 15, 2022, President Biden signed the Inflation Reduction Act into law. Management has reviewed the tax provisions of this legislation and has determined that there are no provisions that would have a material impact on the Company.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company's long-term debt consisted of the following (in thousands): December 31, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 722,000 $ 542,000 Second Lien Notes due 2028 500,000 150,000 1,222,000 692,000 Unamortized discount on Second Lien Notes (7,820) (882) Unamortized debt issuance cost on Second Lien Notes (12,289) (2,587) Total Debt 1,201,891 688,531 Less: Current portion of Second Lien Notes due 2028 28,125 — Long-term debt, net $ 1,173,766 $ 688,531 (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, 2023 and 2022, we had $24.9 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. The Company's five-year maturity related to our Second Lien Notes due 2028 is as follows (in thousands): Payments due 2024 2025 2026 2027 2028 Total Second Lien Notes Due 2028 28,125 37,500 37,500 37,500 359,375 500,000 Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $722.0 million and $542.0 million as of December 31, 2023 and 2022, 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 through the Eleventh Amendment (as defined below) (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with the closing of the acquisition for certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9, the Company executed the Eleventh Amendment to the Credit Agreement on November 30, 2023 (the “Eleventh Amendment”) which secured $425.0 million of incremental commitments under its Credit Facility from existing and new lenders, thereby increasing lender commitments and the borrowing base under the Credit Facility to $1.2 billion from $775.0 million. The maturity date remained unchanged at October 19, 2026 and the maximum credit amounts remained unchanged at $2.0 billion. The Eleventh Amendment also permitted the issuance of up to $350.0 million principal amount of additional Second Lien Notes (as defined below), resulting in an aggregate principal amount of outstanding Second Lien Notes not to exceed $500.0 million and modified certain other terms of the Credit Agreement. Additionally, the Company incurred approximately $20.0 million in third party and legal fees in connection with the amendment. 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 $25.0 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, 2023 and 2022. 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 is payable quarterly and 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 to the Credit Agreement 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, 2023, the Company's weighted average interest rate on Credit Facility borrowings was 8.70%. 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. 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 1.00 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 1.00 to 1.00 as of the last day of each fiscal quarter. As of December 31, 2023, 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 $55.7 million, $26.9 million and $11.3 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amount of commitment fee amortization included in interest expense, net was $1.1 million, $1.2 million and $0.5 million for the years ended December 31, 2023, 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 $50.0 million redemption of the Second Lien Notes on November 29, 2021. On June 14, 2023, the Company entered into the Third Amendment to the Note Purchase Agreement to effectuate the replacement of LIBOR with an adjusted term secured overnight financing rate plus a margin of 0.25% (“Term SOFR”). After the Third Amendment, interest under the Second Lien is payable quarterly and accrues, based on the Company's election at the time of the borrowing, either at Term SOFR plus a margin of 7.5% (“Second Lien Term SOFR Loans”) or at an Alternate Base Rate which is based on the greater of (i) the prime rate; (ii) the greater of the federal funds effective rate or overnight bank funding rate, plus 0.5%; or (iii) Term SOFR plus 1% (“Second Lien ABR Loans”) plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility. Effective November 30, 2023, the Company entered into the Fourth Amendment to the Note Purchase Agreement (the “Fourth Amendment”), which extended the maturity date from December 15, 2026 to December 15, 2028, and upsized the outstanding Second Lien Notes by $350.0 million, with a $7.0 million discount, for net proceeds of $343.0 million, in connection with the closing of certain oil and gas assets in South Texas from Chesapeake Energy Corporation described further in Note 9. The Company evaluated the amendment on a lender-by-lender basis as to whether it represented a debt extinguishment or modification and wrote off approximately $0.2 million in previously unamortized debt issuance costs and $0.1 million in previously unamortized debt discount during the year ended December 31, 2023 which is included within “Interest expense, net” on the consolidated statements of operations. Additionally, the Company incurred approximately $10.6 million in third party fees in connection with the amendment. The new debt issuance cost and discount on the Second Lien Notes will be amortized through the new maturity date of December 15, 2028. The Fourth Amendment also (i) caused the maximum permitted ratio of Total Net Indebtedness to EBITDA (each as defined in the Note Purchase Agreement) for any fiscal quarter in which the maximum ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) under the Credit Agreement is less than 3.00 to 1.00, to be reduced to a ratio that is 0.25 to 1.00 higher than that set forth in the Credit Agreement; (ii) amended the Minimum Asset Coverage Ratio (as defined in the Note Purchase Agreement) to be no less than (A) 1.10 to 1.00 through the fiscal quarter ending March 31, 2024 and (B) 1.25 to 1.00 thereafter, in each case of clause (A) and clause (B), tested on a quarterly basis; (iii) added a financial covenant whereby the Current Ratio (as defined in the Note Purchase Agreement) shall not be less than 1.00 to 1.00; (iv) decreased the mortgage coverage and title requirements from 90% to 85%; and (v) modified certain other terms of the Note Purchase Agreement. Additionally, the Second Lien Notes implemented a quarterly requirement for repayment of Notes, beginning on June 15, 2024, requiring the Company to redeem the Notes on each Interest Payment Date in an amount equal to $9.4 million provided the ratio of Total Indebtedness to EBITDA not exceed 2.25 to 1.00, subject to certain exceptions. 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. As of December 31, 2023, the Company's interest rate on Second Lien borrowings was 13.13%. As of December 31, 2023, the Company was in compliance with all financial covenants under the Second Lien. 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 with at least 85% of estimated PV-9 (defined below) of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. As of December 31, 2023, net amounts recorded for the Second Lien Notes were $479.9 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $24.4 million, $15.0 million and $17.8 million for the years ended December 31, 2023, 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, 2023, 2022 and 2021, the Company capitalized $30.6 million, $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility and Second Lien Notes. Additionally, the Company wrote-off $1.2 million and $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2023, 2022 and 2021, respectively, related to changes under our Credit Facility and Second Lien Notes.

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	Price-Risk Management Activities Derivatives are recorded on the consolidated balance sheets at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Net gain (loss) on commodity derivatives” 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, 2023, 2022 and 2021, the Company recorded gains of $235.8 million and losses of $78.0 million and $123.0 million, respectively, relating to our commodity derivative activities. The Company received net cash payments of $88.7 million, and made net cash payments of $219.6 million and $70.6 million for settled derivative contracts during the years ended December 31, 2023, 2022 and 2021, respectively. During the years ended December 31, 2023, 2022 and 2021, the Company recorded gains of $5.5 million, $4.1 million and less than $0.1 million, respectively, related to valuation changes on the 2021, 2022 and 2023 WTI (“West Texas Intermediate”) Contingency Payouts. At December 31, 2023 and 2022, we had $13.5 million and $6.9 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 2024 and 2023, respectively. At December 31, 2023 and 2022, we also had $1.0 million and $6.0 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 2024 and 2023, 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, 2023 there was $116.5 million and $55.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $5.5 million and $2.5 million in current unsettled derivative liabilities and long-term unsettled derivative liabilities, respectively. At December 31, 2022, the Company had $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. 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 a $163.6 million net fair value asset at December 31, 2023 and $28.2 million net fair value asset at December 31, 2022. 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, 2023. 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 2024 Contracts 1Q24 1,092,000 $ 77.39 2Q24 1,118,550 $ 77.18 3Q24 1,147,620 $ 76.29 4Q24 1,130,100 $ 75.96 2025 Contracts 1Q25 756,000 $ 72.18 2Q25 764,400 $ 72.05 3Q25 772,800 $ 71.95 4Q25 680,800 $ 71.60 2026 Contracts 1Q26 472,500 $ 68.94 2Q26 455,000 $ 68.98 3Q26 432,400 $ 69.03 4Q26 386,150 $ 69.09 Collar Contracts 2024 Contracts 1Q24 319,700 $ 58.95 $ 71.74 2Q24 215,000 $ 61.08 $ 73.57 3Q24 184,000 $ 63.50 $ 75.53 4Q24 184,000 $ 63.00 $ 75.35 2025 Contracts 1Q25 238,500 $ 64.00 $ 74.62 2Q25 227,500 $ 60.80 $ 72.22 2026 Contracts 1Q26 90,000 $ 64.00 $ 71.50 2Q26 91,000 $ 64.00 $ 71.50 3Q26 92,000 $ 64.00 $ 71.50 3-Way Collar Contracts 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2024 Contracts 1Q24 364,000 $ 1.47 2Q24 364,000 $ 1.47 3Q24 368,000 $ 1.47 4Q24 368,000 $ 1.47 2025 Contracts 1Q25 360,000 $ 1.75 2Q25 364,000 $ 1.75 3Q25 368,000 $ 1.75 4Q25 368,000 $ 1.75 Calendar Monthly Roll Differential Swaps 2024 Contracts 1Q24 364,000 $ 0.69 2Q24 364,000 $ 0.69 3Q24 368,000 $ 0.69 4Q24 368,000 $ 0.69 2025 Contracts 1Q25 360,000 $ 0.43 2Q25 364,000 $ 0.43 3Q25 368,000 $ 0.43 4Q25 368,000 $ 0.43 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 2024 Contracts 1Q24 9,506,000 $ 4.03 2Q24 15,390,000 $ 3.60 3Q24 16,100,000 $ 3.71 4Q24 16,100,000 $ 4.04 2025 Contracts 1Q25 13,950,000 $ 4.25 2Q25 14,105,000 $ 3.72 3Q25 16,560,000 $ 3.86 4Q25 10,590,000 $ 4.15 2026 Contracts 1Q26 10,580,000 $ 4.49 2Q26 10,465,000 $ 3.56 3Q26 10,580,000 $ 3.74 4Q26 10,120,000 $ 4.14 Collar Contracts 2024 Contracts 1Q24 9,661,000 $ 3.94 $ 5.83 2Q24 4,643,000 $ 3.64 $ 4.28 3Q24 3,878,000 $ 3.77 $ 4.76 4Q24 3,865,000 $ 4.01 $ 5.34 2025 Contracts 1Q25 5,130,000 $ 4.00 $ 5.32 2Q25 4,914,000 $ 3.25 $ 3.98 3Q25 920,000 $ 3.50 $ 3.99 4Q25 920,000 $ 3.75 $ 4.65 3-Way Collar Contracts 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 2024 Contracts 1Q24 16,380,000 $ (0.03) 2Q24 16,380,000 $ (0.29) 3Q24 16,560,000 $ (0.25) 4Q24 16,560,000 $ (0.28) 2025 Contracts 1Q25 7,200,000 $ (0.09) 2Q25 7,280,000 $ (0.26) 3Q25 7,360,000 $ (0.23) 4Q25 7,360,000 $ (0.26) NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2024 Contracts 1Q24 491,400 $ 25.92 2Q24 491,400 $ 25.92 3Q24 496,800 $ 25.92 4Q24 496,800 $ 25.92 2025 Contracts 1Q25 360,000 $ 23.88 2Q25 364,000 $ 23.88 3Q25 368,000 $ 23.88 4Q25 368,000 $ 23.88

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $89.5 million for 2024, $102.0 million for 2025, $107.0 million for 2026, $104.6 million for 2027, $92.2 million for 2028 and $689.9 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, 2023. However, our consolidated 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 $14.0 million for the year ended December 31, 2023. Additionally, we have drilling commitments amounting to $4.8 million for 2024 and $2.1 million for 2025 and other contractual commitments related to tubing purchases amounting to $1.7 million for 2024. 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, 2023
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 $5.5 million, $5.1 million and $4.6 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized share-based compensation was $0.3 million, $0.2 million and $0.2 million and for the years ended December 31, 2023, 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 2016 Plan and Inducement Plan were 563,127 and 140,446, respectively, at December 31, 2023. 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, 2023, we had no unrecognized compensation cost related to stock option awards. The following table represents stock option award activity for the years ended December 31, 2023, 2022 and 2021: Options Outstanding Options Wtd. Avg. Wtd. Avg. Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands) Balance outstanding, January 1, 2023 196,162 26.46 4.4 438 Options exercised — — Options expired — — Options outstanding, December 31, 2023 196,162 $ 26.46 3.4 $ 525 Options exercisable, December 31, 2023 196,162 $ 26.46 3.4 $ 525 The total intrinsic value of stock options exercised during the year ended December 31, 2022 was $0.3 million. There were no stock options exercised during the years ended year ended December 31, 2023 or 2021. 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, 2023, we had unrecognized compensation expense of $4.3 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 1.8 years. The total fair value of shares vested during the years ended December 31, 2023, 2022 and 2021 were $3.4 million, $7.7 million and $2.6 million, respectively. The following table provides information regarding restricted stock unit activity for the year ended December 31, 2023: Shares Wtd. Avg. Restricted stock units outstanding, December 31, 2022 227,114 21.18 Restricted stock units granted 197,073 23.81 Restricted stock units forfeited (1,424) 25.44 Restricted stock units vested (137,600) 17.80 Restricted stock units outstanding, December 31, 2023 285,163 $ 24.61 Performance-Based Stock Units On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned was 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 contained market conditions which allowed 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 had 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 contained market conditions which allowed 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 was based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level was calculated based on actual stock price performance achieved during the performance period. The awards had 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 On February 23, 2023, the Company granted 120,749 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, 2023 to December 31, 2025. 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 $31.18 per unit or 136.28% 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, 2023, we had unrecognized compensation expense of $4.2 million related to our PSUs based on the assumption of 100.0% target payout. The remaining weighted-average performance period is 1.6 years. The following table provides information regarding PSU activity for the year ended December 31, 2023: Shares Wtd. Avg. PSUs outstanding, December 31, 2022 283,500 $ 23.18 PSUs granted 120,749 $ 31.18 PSUs incremental shares granted 142,021 $ 13.13 PSUs vested (303,410) $ 13.13 PSUs outstanding, December 31, 2023 242,860 $ 33.84 Employee Savings Plan We have a savings plan under Section 401(k) of the Internal Revenue Code. The Company contributed on behalf of eligible employees an amount up to 100% of the first 6% of compensation based on the contributions made by the eligible employees in 2023 and 2022. The Company's plan contributions of $0.8 million, $0.6 million and $0.5 million for the years ended December 31, 2023, 2022 and 2021, respectively, were paid in cash during each pay period. These amounts were recorded as “General and administrative, net” on the accompanying consolidated statements of operations.

Leases Leases (Notes)

Leases Leases (Notes)	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended December 31, 2022 Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 21,631 $ 15,219 Property and equipment acquisitions - operating leases — — Total lease costs in property, plant and equipment additions $ 21,631 $ 15,219 Year Ended December 31, 2023 Year Ended December 31, 2022 Lease Costs Included in the Consolidated Statements of Operations Lease operating costs - short-term leases $ 13,228 $ 6,275 Lease operating costs - operating leases 8,485 8,304 General and administrative, net - operating leases 808 754 Total lease cost expensed $ 22,521 $ 15,333 The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2023 As of December 31, 2022 Weighted-average remaining lease term (in years) 5.0 2.5 Weighted-average discount rate 7.8 % 4.6 % As of December 31, 2023, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2023 2024 $ 4,860 2025 3,296 2026 1,891 2027 1,367 2028 1,348 Thereafter 2,877 Total undiscounted lease payments $ 15,639 Present value adjustment (2,739) Net operating lease liabilities $ 12,900 Current lease liability $ 4,001 Non-current lease liability $ 8,899 Supplemental cash flow information related to leases was as follows (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 9,531 $ 9,052 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 6,134 $ 5,342 Rental and lease expense was $22.5 million, $14.6 million and $7.0 million for the years ended December 31, 2023, 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, 2023
Business Combinations [Abstract]
Acquisitions and Dispositions	Acquisitions and Dispositions 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 years ended December 31, 2023, 2022 and 2021, the Company recorded losses of $0.9 million, $1.2 million and less than $0.1 million, respectively, related to the 2021 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the consolidated statements of operations and recorded $1.6 million in earn-out consideration payable to the seller related to the 2023 and 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 consisted of cash and 1,300,000 shares of our common stock 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. 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 consisted of cash, 4,148,472 shares of our common stock based on the Company's share price on the closing date, accrued purchase price adjustments receivable and contingent consideration. 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, 2023, the Company recorded gains of $1.0 million related valuation changes in the 2022 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations. Additionally, as part of our post-close settlement we settled the 2022 WTI Contingency during the second quarter of 2023. As such, we recorded a non-cash gain of $1.1 million during the year ended December 31, 2023, and we are no longer required to make a contingency payment related to the 2022 WTI Contingency Payout. 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 $ 219,866 Equity consideration 117,651 Fair value of contingent consideration 7,422 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 cash 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 cash consideration was approximately $80.1 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. 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. 2023 Chesapeake Acquisition On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from Chesapeake, with consideration comprised of (i) cash paid at the closing of the Chesapeake Transaction, (ii) accrued purchase price adjustments receivable which were substantially collected in January 2024, (iii) a deferred acquisition liability due on the first anniversary of the closing of the Chesapeake Transaction and (iv) an earn-out payment contingent upon the average monthly settlement price of NYMEX West Texas Intermediate crude oil for the 12 month period beginning December 2023 (the “2023 WTI Contingency Payout”). If the average monthly settlement price of WTI during the 12 month period (a) exceeds $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $50 million or (b) is between $75 per barrel and $80 per barrel, SilverBow shall pay Chesapeake an amount equal to $25 million. If the average monthly settlement price of WTI during the 12 month period is below $75 per barrel, SilverBow shall not owe Chesapeake a contingent earn-out payment. During the year ended December 31, 2023, the Company recorded gains of $4.3 million related to valuation changes in the 2023 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying consolidated statements of operations. 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 the Chesapeake Transaction as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The Chesapeake Transaction was funded with borrowings under the Company's Credit Facility, proceeds from the issuance of additional Second Lien Notes and cash on hand. 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 $ 594,588 Accrued purchase price adjustments receivable (18,100) Fair value of contingent consideration 16,933 Deferred acquisition liability 50,000 Total Consideration 643,421 Transaction costs 10,003 Total Cost of Transaction $ 653,424 Allocation of Total Cost Assets Oil and gas properties $ 657,921 Right of use assets 187 Total assets 658,108 Liabilities Accounts payable and accrued liabilities 3,040 Lease liability 187 Asset retirement obligations 1,457 Total Liabilities 4,684 Net Assets Acquired $ 653,424

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2023
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, 2022 WTI Contingency Payout and 2023 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. Acquisitions . The Company recognized the assets acquired in our 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, 2023 and 2022, 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, 2023 Assets Natural Gas Derivatives $ 116,410 $ — $ 116,410 $ — Natural Gas Basis Derivatives 6,111 — 6,111 — Oil Derivatives 39,940 — 39,940 — Oil Basis Derivatives 708 — 708 — NGL Derivatives 8,494 — 8,494 — Liabilities Natural Gas Derivatives 641 — 641 — Natural Gas Basis Derivatives 2,599 — 2,599 — Oil Derivatives 3,302 — 3,302 — Oil Basis Derivatives 921 — 921 — NGL Derivatives 550 — 550 — 2023 WTI Contingency Payout 12,682 — 12,682 — 2021 WTI Contingency Payout 2,310 — 2,310 — 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 — 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, 2023
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, 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 Accretion expense 985 Liabilities incurred for new wells, acquired wells and facilities construction 1,883 Reductions due to plugged wells and facilities (718) Revisions in estimates 554 Asset Retirement Obligations as of December 31, 2023 $ 13,160 At December 31, 2023 and 2022, approximately $1.6 million and $1.3 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, 2023
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 oil and gas 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 acquisitions, • 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, 2023, 2022 and 2021, such internal costs when capitalized totaled $5.5 million, $4.3 million and $4.8 million, respectively. There was no capitalized interest on our unproved properties for the years ended December 31, 2023, 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 $ 3,562,268 $ 2,506,853 Unproved oil and gas properties 28,375 16,272 Furniture, fixtures, and other equipment 6,517 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,223,241) (1,004,044) Property and Equipment, Net $ 2,373,919 $ 1,525,179 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 the years ended December 31, 2023, 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 or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.
Revenue Recognition	Revenue Recognition . Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices, consistent with contractual terms common in the oil and gas industry. These contracts typically provide for cash settlement within 25 days following each production month. 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. Our oil and gas sales are recognized based on the actual volumes sold to the purchasers.
Accounts Receivable	Accounts Receivable, Net . We assess the collectibility of accounts receivable based on a broad range of reasonable and forward-looking information including historical losses, current economic conditions, future forecasts and contractual terms. The Company's credit losses based on these assessments are considered immaterial. At both December 31, 2023 and 2022, we had an allowance for credit losses of less than $0.1 million. The allowance for credit losses has been deducted from the total “Accounts receivable, net” balance on the accompanying consolidated balance sheets.
Supervision Fees	Supervision Fees
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, 2023, 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. We recorded an income tax provision of $83.6 million, $9.6 million and $6.4 million for the years ended December 31, 2023, 2022 and 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 determined it had 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 $83.6 million which was primarily attributable to deferred federal and current and deferred state income tax expense of $82.9 million on income before taxes of $381.3 million and $0.7 million of non-deductible expenses for the year ended December 31, 2023. 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	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 $ 32,225 $ 23,660 Accrued operating expenses 23,104 10,572 Accrued compensation costs 10,208 4,814 Asset retirement obligations – current portion 1,576 1,284 Accrued non-income based taxes 3,870 4,849 WTI contingency liability - current portion 14,282 1,600 Accrued corporate and legal fees 208 388 Other payables (1)(2) 13,343 13,033 Total accounts payable and accrued liabilities $ 98,816 $ 60,200 (1) Included in Other Payables is $1.0 million and $6.0 million in payables for settled derivatives for the years ended December 31, 2023 and 2022, respectively. (2) Included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our Chesapeake Transaction for the year ended December 31, 2023.
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. Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. As of December 31, 2023, there was $2.2 million and $5.6 million, in current and long-term restricted cash, respectively. There was no restricted cash as of December 31, 2022. The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet presentation (in thousands): December 31, December 31, Cash and cash equivalents $ 969 $ 792 Current restricted cash (1) 2,200 — Long-term restricted cash (2) 5,560 — Total cash, cash equivalents and restricted cash $ 8,729 $ 792 (1) Current restricted cash is included in “Other Current Assets” on the accompanying consolidated balance sheet. (2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying consolidated balance sheet.
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, 2023, 2022 and 2021, we purchased 131,951, 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. Preferred Stock Purchase Rights. On September 20, 2022, the Board declared a dividend distribution of one preferred stock purchase right (each, a “Right”) for each outstanding share of our common stock. As of and after the Distribution Date (as defined in the Rights Agreement, as amended dated May 16, 2023, between the Company and American Stock Transfer & Trust Company (the “Rights Agreement”) governing the Rights), each right will become exercisable to purchase one one-thousandth of a share of Series B Junior Participating Preferred Stock, par value $0.01 per share (the “Preferred Stock”), at a purchase price of $160.00. This portion of a share of Preferred Stock would give the holder thereof approximately the same dividend, voting, and liquidation rights as would one share of Common Stock. Prior to exercise, the Right does not give its holder any dividend, voting or liquidation rights. The Rights will expire on the earliest of (a) 5:00 p.m., New York City time on the day after the 2024 annual shareholders’ meeting, (b) the time at which the Rights are redeemed (as described in the Rights Agreement), and (c) the time at which the Rights are exchanged in full.
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, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated 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, and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, issued in December 2022. 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. This guidance provides an optional practical expedient that allows qualifying modifications to be accounted for as a debt modification rather than be analyzed under existing guidance to determine if the modification should be accounted for as a debt extinguishment. The Company adopted this accounting pronouncement in conjunction with the execution of the Third Amendment to the Note Purchase Agreement in June 2023 and elected to apply this optional expedient. See Note 4 – Long-Term Debt for further discussion of the Company’s accounting for its existing debt and related issuance costs. The adoption of this accounting standard did not have a material impact on the Company's consolidated financial statements or disclosures. 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, and the Company adopted the guidance on January 1, 2023. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements or disclosures. In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The guidance aims to improve the effectiveness of income tax disclosures primarily through improvements to the income tax rate reconciliation disclosure along with information on income taxes paid. The guidance is effective for the Company for fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of this standard; however, we do not expect it to have a material impact on our disclosures. In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The guidance requires disclosures of certain general information related to the Company's segment. This includes information on the factors used to identify reportable segments, the types of products and services from which report segments generate revenues and whether operating segments have been aggregated. The new requirements will result in incremental disclosures in annual and interim reports. This guidance will apply to fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The new guidance must be applied retrospectively to all prior periods presented in the financial statements unless impracticable with early adoption permitted. We are currently evaluating the impact of this standard.

Earnings Per Share Earning Per

Earnings Per Share Earning Per Share (Policies)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	12 Months Ended
	Dec. 31, 2023
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, 2023, 2022 and 2021, the Company capitalized $30.6 million, $7.3 million and $3.6 million, respectively, for debt issuance costs incurred in connection with the amendments to our Credit Facility and Second Lien Notes. Additionally, the Company wrote-off $1.2 million and $0.4 million and $0.2 million in debt issuance costs during the years ended December 31, 2023, 2022 and 2021, respectively, related to changes under our Credit Facility and Second Lien Notes.

Price-Risk Management Price-R_2

Price-Risk Management Price-Risk Management (Policies)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management Activities Derivatives are recorded on the consolidated balance sheets at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Net gain (loss) on commodity derivatives” 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, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We have gas transportation and processing minimum obligations amounting to $89.5 million for 2024, $102.0 million for 2025, $107.0 million for 2026, $104.6 million for 2027, $92.2 million for 2028 and $689.9 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, 2023. However, our consolidated 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 $14.0 million for the year ended December 31, 2023. Additionally, we have drilling commitments amounting to $4.8 million for 2024 and $2.1 million for 2025 and other contractual commitments related to tubing purchases amounting to $1.7 million for 2024. 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, 2023
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 $5.5 million, $5.1 million and $4.6 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized share-based compensation was $0.3 million, $0.2 million and $0.2 million and for the years ended December 31, 2023, 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 2016 Plan and Inducement Plan were 563,127 and 140,446, respectively, at December 31, 2023.

Leases Leases (Policies)

Leases Leases (Policies)	12 Months Ended
	Dec. 31, 2023
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, 2023
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, 2022 WTI Contingency Payout and 2023 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. Acquisitions . The Company recognized the assets acquired in our 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, 2023
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, 2023
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our consolidated financial statements. There were no material subsequent events requiring additional disclosure in these Notes to Consolidated Financial Statements.
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 $ 3,562,268 $ 2,506,853 Unproved oil and gas properties 28,375 16,272 Furniture, fixtures, and other equipment 6,517 6,098 Less – Accumulated depreciation, depletion, amortization & impairment (1,223,241) (1,004,044) Property and Equipment, Net $ 2,373,919 $ 1,525,179
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, 2023, 2022 and 2021 (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Oil, natural gas and NGLs sales: Oil $ 402,728 $ 239,247 $ 98,607 Natural gas 187,340 451,863 267,687 NGLs 62,291 62,310 40,906 Total $ 652,358 $ 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 $ 32,225 $ 23,660 Accrued operating expenses 23,104 10,572 Accrued compensation costs 10,208 4,814 Asset retirement obligations – current portion 1,576 1,284 Accrued non-income based taxes 3,870 4,849 WTI contingency liability - current portion 14,282 1,600 Accrued corporate and legal fees 208 388 Other payables (1)(2) 13,343 13,033 Total accounts payable and accrued liabilities $ 98,816 $ 60,200 (1) Included in Other Payables is $1.0 million and $6.0 million in payables for settled derivatives for the years ended December 31, 2023 and 2022, respectively. (2) Included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our Chesapeake Transaction for the year ended December 31, 2023.
Schedule of Cash and Cash Equivalents	The following table is a reconciliation of the total cash and cash equivalents and restricted cash in the accompanying consolidated statements of cash flows and their corresponding balance sheet presentation (in thousands): December 31, December 31, Cash and cash equivalents $ 969 $ 792 Current restricted cash (1) 2,200 — Long-term restricted cash (2) 5,560 — Total cash, cash equivalents and restricted cash $ 8,729 $ 792
Oil and Gas receipts greater than 10%	For the years ended December 31, 2023, 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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Kinder Morgan 15 % 22 % 26 % Shell Trading 11 % 12 % 12 % Enterprise Products 29 % * * Plains Marketing * 11 % 10 % Trafigura US * 14 % 16 % Twin Eagle * * 15 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ 297,716 23,371 $ 12.74 $ 340,437 19,748 $ 17.24 $ 86,759 13,118 $ 6.61 Dilutive Securities: Restricted Stock Unit Awards 104 162 285 Performance Based Stock Unit Awards 76 149 117 Stock Option Awards 20 38 — Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ 297,716 23,571 $ 12.63 $ 340,437 20,097 $ 16.94 $ 86,759 13,520 $ 6.42
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following is a table of antidilutive options and shares excluded from the computation of Diluted EPS for the periods indicated below (in thousands): Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Antidilutive Securities: Stock Option Awards — 1 286 Restricted Stock Unit Awards 8 5 — Performance Based Stock Unit Awards — — —

Provision (Benefit) for Incom_2

Provision (Benefit) for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Income (Loss) Before Income Taxes $ 381,329 $ 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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Current: Federal $ — $ — $ — State 527 (25) 186 Total current income tax provision (benefit) 527 (25) 186 Deferred: Federal 80,634 7,188 5,500 State 2,452 2,437 712 Total deferred income tax provision (benefit) 83,086 9,625 6,212 Total tax provision (benefit) $ 83,613 $ 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, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021 Federal Statutory Rate 21.0 % 21.0 % 21.0 % State tax provisions (benefits), net of federal benefits 0.8 % 0.7 % 1.0 % Non-deductible expenses 0.2 % 0.4 % 0.6 % Other, net (0.1) % (0.1) % 0.6 % Valuation allowance adjustments — % (19.3) % (16.2) % Effective rate 21.9 % 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, 2023 and 2022 were as follows (in thousands): December 31, 2023 December 31, 2022 Deferred tax assets: Federal net operating loss (“NOL”) carryovers $ 142,694 $ 130,296 Other carryover items 683 649 Asset retirement obligations 2,842 2,258 Share-based compensation 491 439 Lease liability 2,709 2,589 Interest 21,528 8,798 Other 1,253 963 Total deferred tax assets $ 172,200 $ 145,992 Deferred tax liabilities: Oil and gas exploration and development costs $ (232,902) $ (141,771) Derivative contracts (35,336) (16,943) Leased assets (2,707) (2,536) Other (482) (883) Total deferred tax liabilities (271,427) (162,133) Net deferred tax asset (liabilities) $ (99,227) $ (16,141) State net deferred tax liabilities $ (5,905) $ (3,453) Federal net deferred tax liabilities (93,322) (12,688) Net deferred tax asset (liabilities) $ (99,227) $ (16,141)

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Long-term debt	The Company's long-term debt consisted of the following (in thousands): December 31, 2023 December 31, 2022 Credit Facility Borrowings due 2026 (1) $ 722,000 $ 542,000 Second Lien Notes due 2028 500,000 150,000 1,222,000 692,000 Unamortized discount on Second Lien Notes (7,820) (882) Unamortized debt issuance cost on Second Lien Notes (12,289) (2,587) Total Debt 1,201,891 688,531 Less: Current portion of Second Lien Notes due 2028 28,125 — Long-term debt, net $ 1,173,766 $ 688,531 (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, 2023 and 2022, we had $24.9 million and $8.7 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. The Company's five-year maturity related to our Second Lien Notes due 2028 is as follows (in thousands): Payments due 2024 2025 2026 2027 2028 Total Second Lien Notes Due 2028 28,125 37,500 37,500 37,500 359,375 500,000

Price-Risk Management Price-R_3

Price-Risk Management Price-Risk Management (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023. 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 2024 Contracts 1Q24 1,092,000 $ 77.39 2Q24 1,118,550 $ 77.18 3Q24 1,147,620 $ 76.29 4Q24 1,130,100 $ 75.96 2025 Contracts 1Q25 756,000 $ 72.18 2Q25 764,400 $ 72.05 3Q25 772,800 $ 71.95 4Q25 680,800 $ 71.60 2026 Contracts 1Q26 472,500 $ 68.94 2Q26 455,000 $ 68.98 3Q26 432,400 $ 69.03 4Q26 386,150 $ 69.09 Collar Contracts 2024 Contracts 1Q24 319,700 $ 58.95 $ 71.74 2Q24 215,000 $ 61.08 $ 73.57 3Q24 184,000 $ 63.50 $ 75.53 4Q24 184,000 $ 63.00 $ 75.35 2025 Contracts 1Q25 238,500 $ 64.00 $ 74.62 2Q25 227,500 $ 60.80 $ 72.22 2026 Contracts 1Q26 90,000 $ 64.00 $ 71.50 2Q26 91,000 $ 64.00 $ 71.50 3Q26 92,000 $ 64.00 $ 71.50 3-Way Collar Contracts 2024 Contracts 1Q24 8,247 $ 45.00 $ 57.50 $ 67.85 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2024 Contracts 1Q24 364,000 $ 1.47 2Q24 364,000 $ 1.47 3Q24 368,000 $ 1.47 4Q24 368,000 $ 1.47 2025 Contracts 1Q25 360,000 $ 1.75 2Q25 364,000 $ 1.75 3Q25 368,000 $ 1.75 4Q25 368,000 $ 1.75 Calendar Monthly Roll Differential Swaps 2024 Contracts 1Q24 364,000 $ 0.69 2Q24 364,000 $ 0.69 3Q24 368,000 $ 0.69 4Q24 368,000 $ 0.69 2025 Contracts 1Q25 360,000 $ 0.43 2Q25 364,000 $ 0.43 3Q25 368,000 $ 0.43 4Q25 368,000 $ 0.43 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 2024 Contracts 1Q24 9,506,000 $ 4.03 2Q24 15,390,000 $ 3.60 3Q24 16,100,000 $ 3.71 4Q24 16,100,000 $ 4.04 2025 Contracts 1Q25 13,950,000 $ 4.25 2Q25 14,105,000 $ 3.72 3Q25 16,560,000 $ 3.86 4Q25 10,590,000 $ 4.15 2026 Contracts 1Q26 10,580,000 $ 4.49 2Q26 10,465,000 $ 3.56 3Q26 10,580,000 $ 3.74 4Q26 10,120,000 $ 4.14 Collar Contracts 2024 Contracts 1Q24 9,661,000 $ 3.94 $ 5.83 2Q24 4,643,000 $ 3.64 $ 4.28 3Q24 3,878,000 $ 3.77 $ 4.76 4Q24 3,865,000 $ 4.01 $ 5.34 2025 Contracts 1Q25 5,130,000 $ 4.00 $ 5.32 2Q25 4,914,000 $ 3.25 $ 3.98 3Q25 920,000 $ 3.50 $ 3.99 4Q25 920,000 $ 3.75 $ 4.65 3-Way Collar Contracts 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 2024 Contracts 1Q24 16,380,000 $ (0.03) 2Q24 16,380,000 $ (0.29) 3Q24 16,560,000 $ (0.25) 4Q24 16,560,000 $ (0.28) 2025 Contracts 1Q25 7,200,000 $ (0.09) 2Q25 7,280,000 $ (0.26) 3Q25 7,360,000 $ (0.23) 4Q25 7,360,000 $ (0.26) NGL Swaps (Mont Belvieu) Total Volumes Weighted-Average Price 2024 Contracts 1Q24 491,400 $ 25.92 2Q24 491,400 $ 25.92 3Q24 496,800 $ 25.92 4Q24 496,800 $ 25.92 2025 Contracts 1Q25 360,000 $ 23.88 2Q25 364,000 $ 23.88 3Q25 368,000 $ 23.88 4Q25 368,000 $ 23.88

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Stock Option Activity	The following table represents stock option award activity for the years ended December 31, 2023, 2022 and 2021: Options Outstanding Options Wtd. Avg. Wtd. Avg. Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands) Balance outstanding, January 1, 2023 196,162 26.46 4.4 438 Options exercised — — Options expired — — Options outstanding, December 31, 2023 196,162 $ 26.46 3.4 $ 525 Options exercisable, December 31, 2023 196,162 $ 26.46 3.4 $ 525
Restricted Stock Units Activity	The following table provides information regarding restricted stock unit activity for the year ended December 31, 2023: Shares Wtd. Avg. Restricted stock units outstanding, December 31, 2022 227,114 21.18 Restricted stock units granted 197,073 23.81 Restricted stock units forfeited (1,424) 25.44 Restricted stock units vested (137,600) 17.80 Restricted stock units outstanding, December 31, 2023 285,163 $ 24.61
Performance-Based Stock Units Activity	The following table provides information regarding PSU activity for the year ended December 31, 2023: Shares Wtd. Avg. PSUs outstanding, December 31, 2022 283,500 $ 23.18 PSUs granted 120,749 $ 31.18 PSUs incremental shares granted 142,021 $ 13.13 PSUs vested (303,410) $ 13.13 PSUs outstanding, December 31, 2023 242,860 $ 33.84

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 Year Ended December 31, 2022 Lease Costs Included in the Asset Additions in the Consolidated Balance Sheets Property and equipment acquisitions - short-term leases $ 21,631 $ 15,219 Property and equipment acquisitions - operating leases — — Total lease costs in property, plant and equipment additions $ 21,631 $ 15,219 Year Ended December 31, 2023 Year Ended December 31, 2022 Lease Costs Included in the Consolidated Statements of Operations Lease operating costs - short-term leases $ 13,228 $ 6,275 Lease operating costs - operating leases 8,485 8,304 General and administrative, net - operating leases 808 754 Total lease cost expensed $ 22,521 $ 15,333
Assets and Liabilities, Lessee	The lease term and the discount rate related to the Company's leases are as follows: As of December 31, 2023 As of December 31, 2022 Weighted-average remaining lease term (in years) 5.0 2.5 Weighted-average discount rate 7.8 % 4.6 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of December 31, 2023, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands): As of December 31, 2023 2024 $ 4,860 2025 3,296 2026 1,891 2027 1,367 2028 1,348 Thereafter 2,877 Total undiscounted lease payments $ 15,639 Present value adjustment (2,739) Net operating lease liabilities $ 12,900 Current lease liability $ 4,001 Non-current lease liability $ 8,899
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, 2023 Year Ended December 31, 2022 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows $ 9,531 $ 9,052 Non-cash Investing and Financing Activities Additions to ROU assets obtained from new operating lease liabilities $ 6,134 $ 5,342

Business Combinations and Asset

Business Combinations and Asset Acquisitions (Tables)	Nov. 30, 2023	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 $ 594,588 Accrued purchase price adjustments receivable (18,100) Fair value of contingent consideration 16,933 Deferred acquisition liability 50,000 Total Consideration 643,421 Transaction costs 10,003 Total Cost of Transaction $ 653,424 Allocation of Total Cost Assets Oil and gas properties $ 657,921 Right of use assets 187 Total assets 658,108 Liabilities Accounts payable and accrued liabilities 3,040 Lease liability 187 Asset retirement obligations 1,457 Total Liabilities 4,684 Net Assets Acquired $ 653,424	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 $ 219,866 Equity consideration 117,651 Fair value of contingent consideration 7,422 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, 2023
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, 2023 and 2022, 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, 2023 Assets Natural Gas Derivatives $ 116,410 $ — $ 116,410 $ — Natural Gas Basis Derivatives 6,111 — 6,111 — Oil Derivatives 39,940 — 39,940 — Oil Basis Derivatives 708 — 708 — NGL Derivatives 8,494 — 8,494 — Liabilities Natural Gas Derivatives 641 — 641 — Natural Gas Basis Derivatives 2,599 — 2,599 — Oil Derivatives 3,302 — 3,302 — Oil Basis Derivatives 921 — 921 — NGL Derivatives 550 — 550 — 2023 WTI Contingency Payout 12,682 — 12,682 — 2021 WTI Contingency Payout 2,310 — 2,310 — 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 —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
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, 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 Accretion expense 985 Liabilities incurred for new wells, acquired wells and facilities construction 1,883 Reductions due to plugged wells and facilities (718) Revisions in estimates 554 Asset Retirement Obligations as of December 31, 2023 $ 13,160

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 652,358	$ 753,420	$ 407,200
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	3,562,268	2,506,853
Unproved oil and gas properties	28,375	16,272
Furniture, fixtures, and other equipment	6,517	6,098
Less - Accumulated depreciation, depletion, and amortization	(1,223,241)	(1,004,044)
Property, Plant and Equipment, Net	2,373,919	1,525,179
Accounts Payable and Accrued Liabilities [Abstract]
Trade accounts payable	32,225	23,660
Accrued operating expenses	23,104	10,572
Accrued payroll costs	10,208	4,814
Asset retirement obligation - current portion	1,576	1,284
Accrued taxes	3,870	4,849
WTI contingency liability - current portion	14,282	1,600
Accrued Professional Fees, Current	208	388
Other payables	13,343	13,033
Total accounts payable and accrued liabilities	98,816	60,200
Cash and Cash Equivalents, at Carrying Value	969	792
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	8,729	792	$ 1,121	$ 2,118
Operational Maintenance Project
Accounts Payable and Accrued Liabilities [Abstract]
Escrow Deposit	2,200	0
Plugging and Abandonment Project
Accounts Payable and Accrued Liabilities [Abstract]
Escrow Deposit	$ 5,560	$ 0
Customer Concentration Risk | Revenue Benchmark | Kinder Morgan Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	15%	22%	26%
Customer Concentration Risk | Revenue Benchmark | Shell Trading Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	11%	12%	12%
Customer Concentration Risk | Revenue Benchmark | Enterprise Products Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage	29%
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 | Trafigura US
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage		14%	16%
Customer Concentration Risk | Revenue Benchmark | Twin Eagle Concentration Risk [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration Risk, Percentage			15%
Oil sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 402,728	$ 239,247	$ 98,607
Natural gas sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	187,340	451,863	267,687
NGL sales [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 62,291	$ 62,310	$ 40,906

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2023	May 16, 2023	Sep. 20, 2022	Aug. 13, 2021	Dec. 31, 2020
Summary of Significant Accounting Policies (Textual) [Abstract]
Stockholders Rights Agreement, Percentage of Common Stock Threshold						15%
Total capitalized internal costs	$ 5,500,000	$ 4,300,000	$ 4,800,000
Discount rate for estimated future net revenues from proved properties	10%
Write-down of oil and gas properties	$ 0	0	0
Revenue from Contract with Customer, Excluding Assessed Tax	652,358,000	753,420,000	407,200,000
Allowance for doubtful accounts receivable, current	100,000	100,000
Accounts receivable from oil and gas sales	91,900,000	70,900,000	45,300,000
Accounts receivable related to joint interest owners	7,000,000	5,600,000	1,900,000
Severance tax credit receivables	7,200,000	4,300,000	1,000,000
Other receivables	$ 14,200,000	8,900,000	1,500,000
Percentage of working interest in wells	100%
Total amount of supervision fees charged to wells	$ 12,500,000	8,800,000	5,100,000
Income Tax Expense (Benefit)	83,613,000	9,600,000	6,398,000
Deferred Federal, State and Local, Tax Expense (Benefit)	82,900,000
Income (Loss) Before Income Taxes	381,329,000	350,037,000	93,157,000
Non-deductible tax expenses	700,000
Payables for Settled Derivatives	1,000,000	6,000,000
Payable for Joint Interest Owner Advance	7,800,000
Restricted Cash		0
Total Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 8,729,000	$ 792,000	$ 1,121,000					$ 2,118,000
Treasury Stock, Shares, Acquired	131,951	120,350	74,586
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment		41,375
Series B Junior Participating Preferred Stock, Purchase Price					$ 160
Series B Junior Participating Preferred Stock, Par Value					$ 0.01
ATM Program , Maximum Proceeds							$ 40,000,000
Issuance of common stock	2,810,811		1,222,209
Proceeds From Issuance of common stock	$ 97,309,000	$ 27,000,000	$ 26,956,000
Chesapeake Acquisition
Summary of Significant Accounting Policies (Textual) [Abstract]
Account Receivable for purchase price adjustments				$ (18,100,000)
Operational Maintenance Project
Summary of Significant Accounting Policies (Textual) [Abstract]
Escrow Deposit	2,200,000	0
Plugging and Abandonment Project
Summary of Significant Accounting Policies (Textual) [Abstract]
Escrow Deposit	5,560,000	0
Line of Credit [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Capitalized interest on our unproved properties	$ 0	0	0
Customer Concentration Risk | Revenue Benchmark | Enterprise Products Concentration Risk
Summary of Significant Accounting Policies (Textual) [Abstract]
Concentration Risk, Percentage	29%
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	$ 402,728,000	239,247,000	98,607,000
Natural gas sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	187,340,000	451,863,000	267,687,000
NGL sales [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 62,291,000	$ 62,310,000	$ 40,906,000
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, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Basic EPS:
Net Income (Loss)	$ 297,716	$ 340,437	$ 86,759
Income, Share Amounts	23,371,000	19,748,000	13,118,000
Earnings (Loss) Per Share, Basic	$ 12.74	$ 17.24	$ 6.61
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 297,716	$ 340,437	$ 86,759
Weighted Average Shares Outstanding - Diluted	23,571,000	20,097,000	13,520,000
Earnings (Loss) Per Share, Diluted	$ 12.63	$ 16.94	$ 6.42
Issuance of common stock	2,810,811		1,222,209
Proceeds from Issuance of Common Stock	$ 97,309	$ 0	$ 26,956
Restricted Stock Units (RSUs) [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	104,000	162,000	285,000
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	8,000	5,000	0
Performance Shares [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	76,000	149,000	117,000
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	0	0	0
Stock Options [Member]
Dilutive Securities:
Dilutive Performance Based Stock Unit Awards	20,000	38,000	0
Diluted EPS:
Antidilutive shares not included in the computation of diluted EPS	0	1,000	286,000

Provision (Benefit) for Incom_3

Provision (Benefit) for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary of income (Loss) from continuing operations before taxes
Income (Loss) Before Income Taxes	$ 381,329	$ 350,037	$ 93,157

Consolidated income tax provisi

Consolidated income tax provision (benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary of consolidated income tax provision (benefit)
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
State and Local Income Tax Expense (Benefit), Continuing Operations	527	(25)	186
Current income taxes	527	(25)	186
Deferred Federal Income Tax Expense (Benefit)	80,634	7,188	5,500
Deferred State and Local Income Tax Expense (Benefit)	2,452	2,437	712
Deferred Income Tax Expense (Benefit)	83,086	9,625	6,212
Income tax provision (benefit)	$ 83,613	$ 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, 2023	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%	21%
State tax provisions (benefits), net of federal benefits	0.80%	0.70%	1%
Executive compensation limitation	0.20%	0.40%	0.60%
Other, net	(0.10%)	(0.10%)	0.60%
Valuation allowance adjustments	0%	(19.30%)	(16.20%)
Effective rate	21.90%	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, 2023	Dec. 31, 2022
Deferred tax assets:
DTA, Federal net operating losses (NOLs)	$ 142,694	$ 130,296
DTA, Other loss carryforwards	683	649
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	2,842	2,258
DTA, Unrealized share-based compensation	491	439
Deferred Tax Assets, Tax Deferred Expense, Other	2,709	2,589
Deferred Tax Asset, Interest Carryforward	21,528	8,798
DTA, Other	1,253	963
Total deferred tax assets	172,200	145,992
Deferred tax liabilities:
DTL, Oil and gas exploration and development costs	(232,902)	(141,771)
Deferred Tax Liabilities, Derivatives	(35,336)	(16,943)
Deferred Tax Liabilities, Leasing Arrangements	(2,707)	(2,536)
DTL, Other	(482)	(883)
Total deferred tax liabilites	271,427	162,133
Net deferred tax liabilities	(99,227)	(16,141)
State deferred tax liabilities, net	(5,905)	(3,453)
Federal deferred tax assets, net	$ (93,322)	$ (12,688)

Provision (Benefit) for Incom_4

Provision (Benefit) for Income Taxes (Details Textual) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Effective income tax rate reconciliation, percent	21%	21%	21%
State tax provisions (benefits), net of federal benefits	0.80%	0.70%	1%
Executive compensation limitation	0.20%	0.40%	0.60%
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent	(0.10%)	(0.10%)	0.60%
Valuation allowance adjustments	0%	(19.30%)	(16.20%)
Effective Income Tax Rate Reconciliation, Percent	21.90%	2.70%	6.90%
Operating Loss Carryforward, Income Tax Limitation	80%
Interest Expense Carryforward Under Section 163(j)	$ 102.5
Tax Year 2017 [Member]
Operating Loss Carryforwards	274.2
Tax Year 2023
Operating Loss Carryforwards	$ 405.3

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands						12 Months Ended
	Nov. 30, 2023 USD ($)	Jun. 14, 2023	Jun. 22, 2022	Nov. 29, 2021 USD ($)	Nov. 12, 2021 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Mar. 20, 2023 USD ($)	Dec. 15, 2017 USD ($)
Bank Borrowings
Long-Term Debt, excluding current maturities						$ 1,173,766	$ 688,531
Long-Term Debt, Current Maturities						28,125	0
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility						80,119	41,948	$ 29,129
Payments of Debt Issuance Costs						30,600	7,342	3,611
Write off of Deferred Debt Issuance Cost						1,239	350	229
Second Lien
Long-term Debt						1,201,891	688,531
Long-term Debt, Gross						1,222,000	692,000
Payments of long-term debt						(14,250)	0	(50,000)
New Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net						(24,900)	(8,700)
New Credit Facility [Member] | Line of Credit [Member]
Bank Borrowings
Long-Term Debt, excluding current maturities						$ 722,000	542,000
Line of Credit, current borrowing base	$ 1,200,000								$ 775,000
Line of Credit Facility, Maximum Borrowing Capacity	2,000,000
Line of Credit, Required Security Interest on Oil and Gas Properties			85%
Line of Credit, Letters of Credit Issuable	25,000
Line of Credit, Basis Point Decrease			50
Line of Credit Facility, Commitment Fee Percentage			0.50%
Line of Credit, Additional Interest Due to Payment Default			2%
Debt, Weighted Average Interest Rate						8.70%
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						$ 55,700	26,900	11,300
Commitment fees included in interest expense, net						1,100	1,200	500
Payments of Debt Issuance Costs	20,000					30,600	7,300	3,600
Write off of Deferred Debt Issuance Cost						1,200	400	200
Second Lien
Line of Credit Facility, Increase (Decrease), Net	425,000
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						(12,289)	(2,587)
Long-Term Debt, excluding current maturities						500,000	150,000			$ 198,000
Interest expense including commitment fees and amortization of debt issuance costs relating to the credit facility						24,400	15,000	$ 17,800
Write off of Deferred Debt Issuance Cost						200
Second Lien
Repayments of Debt, to be Paid, Year One						28,125
Repayments of Debt, to be Paid, Year Two						37,500
Repayments of Debt, to be Paid, Year Three						37,500
Repayments of Debt, to be Paid, Year Four						37,500
Repayments of Debt, to be Paid, Year Five						359,375
Long-term Debt						479,900
Long-term Debt, Gross	500,000				$ 150,000					200,000
Debt Instrument, Unamortized Discount	(7,000)					(7,820)	$ (882)			$ (2,000)
Payments of long-term debt				$ (50,000)
Incremental 2nd Lien Notes	350,000
Incremental 2nd Lien Notes, Net	$ 343,000
Discount, Writeoff						100
Professional Fees						$ 10,600
Second Lien, Total Debt to EBITDA Ratio, Maximum	3
Second Lien, Reduction in Total Debt to EBITA Ratio	0.25
Second Lien, Asset Coverage Ratio, Minimum	1.10
Second Lien, Asset Coverage Ratio, after March 31, 2024	1.25
Second Lien, Current Ratio, Minimum	1
Second Lien, Required Security Interest on Oil and Gas Properties	85%				90%
Quarterly Note Repayment Requirement	$ 9,400
Second Lien, Covenant, Total Indebtedness to EBITDA	2.25
Second Lien, Required Security Interest on Proved Reserves	85%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%	9%
Debt Instrument, Interest Rate, Stated Percentage						13.13%
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Second Lien
Debt Instrument, Minimum Margin on SOFR		1%
Debt Instrument, Basis Spread on Variable Rate		6.50%
Second Lien Notes [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Second Lien
Debt Instrument, Minimum Margin on SOFR		0.25%
Debt Instrument, Basis Spread on Variable Rate		7.50%
Second Lien Notes [Member] | Fed Funds Effective Rate Overnight Index Swap Rate
Second Lien
Debt Instrument, Basis Spread on Variable Rate		0.50%

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MMBTU bbl $ / Boe $ / MMBTU	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Derivative [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ 235,800	$ (78,000)	$ (123,000)
Cash Received (Paid) On Settlements of Derivative Contracts | $	88,679	(219,626)	(70,582)
Gain (Loss) on WTI Contingency Payout | $	5,500	4,100	$ 100
Receivables for Settled Derivatives | $	13,500	6,900
Payables for Settled Derivatives | $	1,000	6,000
Derivative, Fair Value, Net | $	163,600	28,200
Other Current Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	116,500	52,500
Other Noncurrent Assets [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	55,100	24,200
Other Current Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	5,500	40,800
Other Noncurrent Liabilities [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 2,500	$ 7,700
Swap [Member] | First Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,092,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	77.39
Swap [Member] | First Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,506,000
Derivative, Swap Type, Average Fixed Price	4.03
Swap [Member] | First Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	491,400
Derivative, Swap Type, Average Fixed Price	25.92
Swap [Member] | Second Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,118,550
Derivative, Swap Type, Average Fixed Price | $ / Boe	77.18
Swap [Member] | Second Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,390,000
Derivative, Swap Type, Average Fixed Price	3.60
Swap [Member] | Second Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	491,400
Derivative, Swap Type, Average Fixed Price	25.92
Swap [Member] | Third Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,147,620
Derivative, Swap Type, Average Fixed Price | $ / Boe	76.29
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Average Fixed Price	3.71
Swap [Member] | Third Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	496,800
Derivative, Swap Type, Average Fixed Price	25.92
Swap [Member] | Fourth Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,130,100
Derivative, Swap Type, Average Fixed Price | $ / Boe	75.96
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Average Fixed Price	4.04
Swap [Member] | Fourth Quarter 2024 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	496,800
Derivative, Swap Type, Average Fixed Price	25.92
Swap [Member] | First Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	756,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	72.18
Swap [Member] | First Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,950,000
Derivative, Swap Type, Average Fixed Price	4.25
Swap [Member] | First Quarter 2025 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Average Fixed Price	23.88
Swap [Member] | Second Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	764,400
Derivative, Swap Type, Average Fixed Price | $ / Boe	72.05
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,105,000
Derivative, Swap Type, Average Fixed Price	3.72
Swap [Member] | Second Quarter 2025 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price	23.88
Swap [Member] | Third Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	772,800
Derivative, Swap Type, Average Fixed Price | $ / Boe	71.95
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Average Fixed Price	3.86
Swap [Member] | Third Quarter 2025 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price	23.88
Swap [Member] | Fourth Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	680,800
Derivative, Swap Type, Average Fixed Price | $ / Boe	71.60
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,590,000
Derivative, Swap Type, Average Fixed Price	4.15
Swap [Member] | Fourth Quarter 2025 | NGL Derivative
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price	23.88
Swap [Member] | First Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	472,500
Derivative, Swap Type, Average Fixed Price | $ / Boe	68.94
Swap [Member] | First Quarter 2026 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,580,000
Derivative, Swap Type, Average Fixed Price	4.49
Swap [Member] | Second Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	455,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	68.98
Swap [Member] | Second Quarter 2026 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,465,000
Derivative, Swap Type, Average Fixed Price	3.56
Swap [Member] | Third Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	432,400
Derivative, Swap Type, Average Fixed Price | $ / Boe	69.03
Swap [Member] | Third Quarter 2026 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,580,000
Derivative, Swap Type, Average Fixed Price	3.74
Swap [Member] | Fourth Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	386,150
Derivative, Swap Type, Average Fixed Price | $ / Boe	69.09
Swap [Member] | Fourth Quarter 2026 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,120,000
Derivative, Swap Type, Average Fixed Price	4.14
Collar Contracts [Member] | First Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	319,700
Derivative, Average Floor Price | $ / Boe	58.95
Derivative, Average Cap Price | $ / Boe	71.74
Collar Contracts [Member] | First Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	9,661,000
Derivative, Average Floor Price	3.94
Derivative, Average Cap Price	5.83
Collar Contracts [Member] | Second Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	215,000
Derivative, Average Floor Price | $ / Boe	61.08
Derivative, Average Cap Price | $ / Boe	73.57
Collar Contracts [Member] | Second Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,643,000
Derivative, Average Floor Price	3.64
Derivative, Average Cap Price	4.28
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	184,000
Derivative, Average Floor Price | $ / Boe	63.50
Derivative, Average Cap Price | $ / Boe	75.53
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,878,000
Derivative, Average Floor Price	3.77
Derivative, Average Cap Price	4.76
Collar Contracts [Member] | Fourth Quarter 2024 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	184,000
Derivative, Average Floor Price | $ / Boe	63
Derivative, Average Cap Price | $ / Boe	75.35
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	3,865,000
Derivative, Average Floor Price	4.01
Derivative, Average Cap Price	5.34
Collar Contracts [Member] | First Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	238,500
Derivative, Average Floor Price | $ / Boe	64
Derivative, Average Cap Price | $ / Boe	74.62
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	5,130,000
Derivative, Average Floor Price	4
Derivative, Average Cap Price	5.32
Collar Contracts [Member] | Second Quarter 2025 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	227,500
Derivative, Average Floor Price | $ / Boe	60.80
Derivative, Average Cap Price | $ / Boe	72.22
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	4,914,000
Derivative, Average Floor Price	3.25
Derivative, Average Cap Price	3.98
Collar Contracts [Member] | Third Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Average Floor Price	3.50
Derivative, Average Cap Price	3.99
Collar Contracts [Member] | Fourth Quarter 2025 | Natural Gas Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Average Floor Price	3.75
Derivative, Average Cap Price	4.65
Collar Contracts [Member] | First Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	90,000
Derivative, Average Floor Price | $ / Boe	64
Derivative, Average Cap Price | $ / Boe	71.50
Collar Contracts [Member] | Second Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	91,000
Derivative, Average Floor Price | $ / Boe	64
Derivative, Average Cap Price | $ / Boe	71.50
Collar Contracts [Member] | Third Quarter 2026 | Oil Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	92,000
Derivative, Average Floor Price | $ / Boe	64
Derivative, Average Cap Price | $ / Boe	71.50
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 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,380,000
Derivative, Swap Type, Average Fixed Price	(0.03)
Basis Swap [Member] | First Quarter 2024 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.47
Basis Swap [Member] | First Quarter 2024 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.69
Basis Swap [Member] | Second Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,380,000
Derivative, Swap Type, Average Fixed Price	(0.29)
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.47
Basis Swap [Member] | Second Quarter 2024 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.69
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Average Fixed Price	(0.25)
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.47
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.69
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Average Fixed Price	(0.28)
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.47
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.69
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,200,000
Derivative, Swap Type, Average Fixed Price	(0.09)
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,280,000
Derivative, Swap Type, Average Fixed Price	(0.26)
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Average Fixed Price	(0.23)
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Average Fixed Price	(0.26)
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative [Member]
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Month Roll Differential Swap
Derivative [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Average Fixed Price | $ / Boe	0.43

Commitments and Contingencies (

Commitments and Contingencies (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Obligations (Textual)
Transportation Expense Incurred	$ 14
Gas transportation and processing obligations [Member]
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	89.5
Contractual Obligation, Due in Second Year	102
Contractual Obligation, Due in Third Year	107
Contractual Obligation, Due in Fourth Year	104.6
Contractual Obligation, Due in Fifth Year	92.2
Contractual Obligation	689.9
Drilling Commitment
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	4.8
Contractual Obligation, Due in Second Year	2.1
Tubing Purchase Commitment
Obligations (Textual)
Contractual Obligation, Due in Next Fiscal Year	$ 1.7

Share-Based Compensation (Detai

Share-Based Compensation (Details 1) - USD ($) $ / shares in Units, $ in Thousands								12 Months Ended
	Dec. 31, 2023	Feb. 23, 2023	Feb. 22, 2023	Dec. 31, 2022	Feb. 23, 2022	Feb. 24, 2021	May 21, 2019	Dec. 31, 2023
Share-based Payment Arrangement, Option [Member]
Stock option activity in shares and weighted average price
Options outstanding, beginning of period, shares								196,162
Options outstanding, beginning of period, weighted average price								$ 26.46
Options, exercised in period								0
Options, Exercises in Period, Weighted Average Exercise Price								$ 0
Options expired								0
Options expired, weighted average price								$ 0
Options outstanding, end of period, shares	196,162			196,162				196,162
Options outstanding, end of period, weighted average price	$ 26.46			$ 26.46				$ 26.46
Options exercisable, end of period, shares	196,162							196,162
Options exercisable, end of period, weighted average price	$ 26.46							$ 26.46
Remaining contract life of outstanding stock options.	3 years 4 months 24 days			4 years 4 months 24 days
Outstanding stock options aggregate intrinsic value	$ 525			$ 438				$ 525
Remaining Contract Life of Exercisable Stock Option	3 years 4 months 24 days
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Exercisable, Intrinsic Value	$ 525							$ 525
Restricted Stock Units (RSUs) [Member]
Restricted stock activity
Restricted units outstanding	285,163			227,114				285,163
Restricted units outstanding, weighted average price	$ 24.61			$ 21.18				$ 24.61
Restricted stock units granted								197,073
Restricted stock units granted, weighted average price								$ 23.81
Restricted stock units forfeited								(1,424)
Restricted stock units forfeited, weighted average price								$ 25.44
Restricted stock units vested								(137,600)
Restricted stock units vested, weighted average price								$ 17.80
Performance Shares [Member]
Restricted stock activity
Restricted units outstanding	242,860			283,500				242,860
Restricted units outstanding, weighted average price	$ 33.84			$ 23.18				$ 33.84
Restricted stock units granted		120,749	120,749		122,111	161,389	99,500
Restricted stock units granted, weighted average price		$ 31.18			$ 36.47	$ 13.13	$ 18.86
Performance based stock units, incremental shares vested					142,021
Performance based stock units, incremental shares vested, weighted average grant date fair value					$ 13.13
Restricted stock units vested			(303,410)		(97,812)			(303,410)
Restricted stock units vested, weighted average price								$ 13.13

Share-Based Compensation (Det_2

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands									12 Months Ended
	Dec. 31, 2023	Feb. 23, 2023	Feb. 22, 2023	Dec. 31, 2022	Feb. 23, 2022	Feb. 24, 2021	Dec. 31, 2020	May 21, 2019	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Stock-Based Compensation Plan
Share-based compensation expenses									$ 5,526	$ 5,086	$ 4,645
Share-based Payment Arrangement, Amount Capitalized									$ 300	200	200
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									$ 800	600	500
2016 Plan
Stock-Based Compensation Plan
Shares available for future grant under stock compensation plans	563,127								563,127
Inducement Plan
Stock-Based Compensation Plan
Shares available for future grant under stock compensation plans	140,446								140,446
General and Administrative Expense [Member]
Stock-Based Compensation Plan
Share-based compensation expenses									$ 5,500	5,100	4,600
Share-based Payment Arrangement, Option [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards	$ 0								0
Outstanding stock options aggregate intrinsic value	$ 525			$ 438					525	438
Remaining contract life of outstanding stock options.	3 years 4 months 24 days			4 years 4 months 24 days
Remaining contract life of exercisable stock option	3 years 4 months 24 days
Intrinsic value of exercised stock option									0	$ 300	0
Restricted Stock Units (RSUs) [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards	$ 4,300								$ 4,300
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards									1 year 9 months 18 days
Restricted units outstanding	285,163			227,114					285,163	227,114
Restricted units outstanding, weighted average price	$ 24.61			$ 21.18					$ 24.61	$ 21.18
Restricted stock units granted									197,073
Restricted stock units granted, weighted average price									$ 23.81
Restricted stock units forfeited									(1,424)
Restricted stock units forfeited, weighted average price									$ 25.44
Restricted stock units vested									137,600
Restricted stock units vested, weighted average price									$ 17.80
Restricted stock units fair value vested									$ 3,400	$ 7,700	$ 2,600
Performance Shares [Member]
Stock Option Awards
Unrecognized compensation cost related to stock awards	$ 4,200								$ 4,200
Stock Units [Abstract]
Weighted average recognition period of cost related to stock awards							1 year 7 months 6 days
Restricted units outstanding	242,860			283,500					242,860	283,500
Restricted units outstanding, weighted average price	$ 33.84			$ 23.18					$ 33.84	$ 23.18
Restricted stock units granted		120,749	120,749		122,111	161,389		99,500
Restricted stock units granted, weighted average price		$ 31.18			$ 36.47	$ 13.13		$ 18.86
Performance based stock units, incremental shares vested					142,021
Performance based stock units, incremental shares vested, weighted average grant date fair value					$ 13.13
Restricted stock units vested			303,410		97,812				303,410
Restricted stock units vested, weighted average price									$ 13.13
Percent of payout for performance based stock units	100%	136.28%			150.93%	157.60%		112.90%	100%
Approved payout for performance based stock units			188%		117%
Performance Period for Award		3 years
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 Shares [Member]
Stock Units [Abstract]
Percent of payout for performance based stock units		0%			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 Shares [Member]
Stock Units [Abstract]
Percent of payout for performance based stock units		200%			200%	200%		200%
Performance Period for Award					3 years	2 years		3 years

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 05, 2021
Lessee, Lease, Description [Line Items]
Lease, Cost	$ 22,521	$ 15,333
Operating Lease, Weighted Average Remaining Lease Term	5 years	2 years 6 months
Operating Lease, Weighted Average Discount Rate, Percent	7.80%	4.60%
Lessee, Operating Lease, Liability, Payments, Due Year One	$ 4,860
Lessee, Operating Lease, Liability, Payments, Due Year Two	3,296
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,891
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,367
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,348
Lessee, Operating Lease, Liability, Payments, Due after Year Five	2,877
Lessee, Operating Lease, Liability, Payments, Due	15,639
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(2,739)
Operating Lease, Liability	12,900
Current lease liability	4,001	$ 8,553
Non-current lease liability	8,899	3,775
Operating Lease, Payments	9,531	9,052
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	6,134	5,342
Rental expense	22,500	14,600	$ 7,000
Building [Member]
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Liability, Payments, Due	8,400
Lessee, Operating Lease, Term of Contract				5 years
Lease Operating Expense [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	13,228	6,275
Operating Lease, Cost	8,485	8,304
General and Administrative Expense [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	808	754
Property, Plant and Equipment [Member]
Lessee, Lease, Description [Line Items]
Short-term Lease, Cost	21,631	15,219
Operating Lease, Cost	0	0
Lease, Cost	$ 21,631	$ 15,219

Acquisitions and Dispositions (

Acquisitions and Dispositions (Details) $ in Thousands									12 Months Ended
	Nov. 30, 2023 USD ($)	Oct. 31, 2022 USD ($)	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, 2023 USD ($)	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Issuance pursuant to acquisitions | shares										5,448,961	3,210,626
Right of use assets									$ 12,888	$ 12,077
Non-current lease liability									8,899	3,775
Asset Retirement Obligations, Noncurrent									11,584	9,171
WTI Contingency Payout						$ 1,900
Gain (Loss) on WTI Contingency Payout									5,500	4,100	$ 100
Derivative, Fair Value, Net									163,600	28,200
Deferred acquisition liability									50,000	0
Other Assets, Current									5,590	2,671
Accounts Payable and Accrued Liabilities, Current									98,816	$ 60,200
Operating Lease, Liability									12,900
Treasury Shares, Shares, Pursuant to Purchase Price Adjustment | shares										41,375
Proceeds from Sale of Property, Plant, and Equipment									713	$ 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									900	$ 1,200	100
2021 WTI Contingency Payable									1,600	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				219,866
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									1,000
Asset Acquisition, Transaction Costs				6,766
Derivative, Fair Value, Net				33,767
Deferred acquisition liability	$ 50,000
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
Operating Lease, Liability	187
Non-Cash Gain on WTI Contingency									1,100
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
Chesapeake Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Acquisition, Consideration Transferred	643,421
Payments to Acquire Oil and Gas Property	594,588
Asset Acquisition, Total Cost of Transaction	653,424
Allocation of Total Cost, Oil and gas properties	657,921
Right of use assets	187
Allocation of Total Cost, Total assets	658,108
Asset Retirement Obligations, Noncurrent	1,457
Allocation of Total Cost, Total Liabilities	4,684
Gain (Loss) on WTI Contingency Payout									$ 4,300
Asset Acquisition, Transaction Costs	10,003
Account Receivable for purchase price adjustments	18,100
2023 WTI Contingency Payout Fair Value	16,933
Accounts Payable and Accrued Liabilities, Current	$ 3,040
WTI Annual Earn Out, Average Monthly Settlement Price 2024, Over $80	80
WTI Annual Earn Out, Average Monthly Settlement Price in 2024, Over $75	75
WTI Annual Earn Out, Average Monthly Settlement Price in 2024, Less than $80	80
WTI Annual Earn Out, Average Monthly Settlement Price in 2024, Below $75	75
2024 WTI Annual Earnout Payment, if WTI over $80	$ 50,000
2024 WTI Annual Earnout Payment, if WTI over $75 and less than $80	$ 25,000

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Natural Gas Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	$ 116,410	$ 25,960
Derivative Liability	641	28,579
Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	6,111	26,023
Derivative Liability	2,599	409
Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	39,940	14,604
Derivative Liability	3,302	19,442
2023 WTI Contingency Payout	12,682
2022 WTI Contingency Payout Fair Value		2,135
2021 WTI Contingency Payout Fair Value	2,310	1,453
Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	708
Derivative Liability	921
NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	8,494	10,134
Derivative Liability	550	104
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
2023 WTI Contingency Payout	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	116,410	25,960
Derivative Liability	641	28,579
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	6,111	26,023
Derivative Liability	2,599	409
Fair Value, Inputs, Level 2 [Member] | Oil Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	39,940	14,604
Derivative Liability	3,302	19,442
2023 WTI Contingency Payout	12,682
2022 WTI Contingency Payout Fair Value		2,135
2021 WTI Contingency Payout Fair Value	2,310	1,453
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative [Member]
Debt Instrument [Line Items]
Derivative Asset	708
Derivative Liability	921
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Debt Instrument [Line Items]
Derivative Asset	8,494	10,134
Derivative Liability	550	104
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
2023 WTI Contingency Payout	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, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 13,160	$ 10,456	$ 6,050
Accretion expense	985	534	$ 306
Liabilities incurred for new wells and facilities construction	1,883	3,032
Asset Retirement Obligation, Liabilities Settled		(57)
Asset Retirement Obligation, Liabilities Plugged	(718)	(22)
Revisions in estimates	554	919
Asset retirement obligation - current portion	$ 1,576	$ 1,284