SilverBow Resources (SBOW) 10-Q 2 May 24 2024 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2024	Apr. 26, 2024
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2024
Entity File Number	1-8754
Entity Registrant Name	SILVERBOW RESOURCES, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	20-3940661
Entity Address, Address Line One	920 Memorial City Way
Entity Address, Address Line Two	Suite 850
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	281
Local Phone Number	874-2700
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	SBOW
Security Exchange Name	NYSE
Entity Filer Category	Accelerated Filer
Document Quarterly Report	true
Document Transition Report	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Central Index Key	0000351817
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q1
Entity Common Stock, Shares Outstanding		25,538,487

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Current Assets:
Cash and cash equivalents	$ 1,446	$ 969
Accounts receivable, net	125,459	138,343
Fair value of commodity derivatives	89,535	116,549
Other current assets	5,652	5,590
Total Current Assets	222,092	261,451
Property and Equipment:
Property and Equipment, full cost method	3,709,469	3,597,160
Less - Accumulated depreciation, depletion, and amortization	(1,315,364)	(1,223,241)
Net Furniture, Fixtures and other equipment	2,394,105	2,373,919
Capitalized Costs, unproved property balance	30,899	28,375
Right of Use Assets	20,658	12,888
Fair value of long-term commodity derivatives	29,432	55,114
Other Long-Term Assets	28,876	31,090
Total Assets	2,695,163	2,734,462
Current Liabilities:
Accounts payable and accrued liabilities	143,684	98,816
Deferred acquisition liability	50,000	50,000
Fair value of commodity derivatives	26,333	5,509
Accrued capital costs	42,114	31,900
Long-Term Debt, Current Maturities	37,500	28,125
Accrued interest	8,325	9,668
Current lease liability	7,765	4,001
Undistributed oil and gas revenues	37,754	20,425
Total Current Liabilities	353,475	248,444
Long-Term Debt	1,039,469	1,173,766
Non-current Lease Liability	12,955	8,899
Deferred Tax Liabilities	94,077	99,227
Asset Retirement Obligation	11,913	11,584
Fair value of long-term commodity derivatives	8,110	2,504
Other Long-Term Liabilities	0	710
Stockholders' Equity:
Preferred Stock, Value, Outstanding	0	0
Common stock, $0.01 par value	260	259
Additional paid-in capital	681,099	679,202
Treasury stock held, at cost	(11,151)	(10,617)
Retained earnings (Accumulated deficit)	504,956	520,484
Total Stockholders' Equity (Deficit)	1,175,164	1,189,328
Total Liabilities and Stockholders' Equity	$ 2,695,163	$ 2,734,462
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	10,000,000	10,000,000
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares, Issued	26,027,103	25,914,956
Common Stock, Shares, Outstanding	25,523,808	25,429,610
Treasury Stock, Shares	503,295	485,346

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Income Statement [Abstract]
Oil and gas sales	$ 256,680	$ 139,954
Costs and Expenses [Abstract]
General and administrative, net	8,791	7,664
Depreciation, depletion, and amortization	92,103	43,998
Accretion of asset retirement obligation	316	224
Lease operating costs	31,825	20,560
Workovers	610	779
Transportation and gas processing	35,199	11,520
Severance and other taxes	16,212	9,385
Operating Expenses	185,056	94,130
Operating Income (Loss)	71,624	45,824
Net gain (loss) on commodity derivatives	(56,078)	92,249
Interest expense, net	(36,017)	(16,745)
Other Nonoperating Income (Expense)	156	(24)
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	(20,315)	121,304
Provision (Benefit) for Income Taxes	(4,787)	26,812
Net Income (Loss)	$ (15,528)	$ 94,492
Per Share Amounts-
Earnings Per Share, Basic	$ (0.61)	$ 4.21
Earnings Per Share, Diluted	$ (0.61)	$ 4.17
Weighted Average Shares Outstanding - Basic	25,445	22,440
Weighted Average Shares Outstanding - Diluted	25,445	22,634

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings (Accumulated Deficit)
Beginning Balance at Dec. 31, 2022	$ 791,579	$ 227	$ 576,118	$ (7,534)	$ 222,768
Purchase of treasury shares	(2,945)	0	0	(2,945)	0
Vesting of share-based compensation	0	4	(4)	0	0
Amortization of share-based compensation	1,179	0	1,179	0	0
Net Income (Loss)	94,492	0	0	0	94,492
Ending Balance at Mar. 31, 2023	$ 884,305	231	577,293	(10,479)	317,260
Purchase of treasury stock (shares)	126,240
Vesting of share-based compensation (shares)	418,518
Beginning Balance at Dec. 31, 2023	$ 1,189,328	259	679,202	(10,617)	520,484
Purchase of treasury shares	(534)	0	0	(534)	0
Vesting of share-based compensation	0	1	(1)	0	0
Amortization of share-based compensation	1,898	0	1,898	0	0
Net Income (Loss)	(15,528)	0	0	0	(15,528)
Ending Balance at Mar. 31, 2024	$ 1,175,164	$ 260	$ 681,099	$ (11,151)	$ 504,956
Purchase of treasury stock (shares)	17,949
Vesting of share-based compensation (shares)	112,147

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Cash Flows from Operating Activities:
Net Income (Loss)	$ (15,528)	$ 94,492
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation, depletion, and amortization	92,103	43,998
Accretion of asset retirement obligation	316	224
Deferred income taxes	(5,150)	26,612
Stock-based compensation expenses	1,830	1,124
Loss (gain) on derivatives	56,078	(92,249)
Cash Received (Paid) On Settlements of Derivative Contracts	38,371	18,699
Settlements of asset retirement obligations	(2)	(3)
Other Noncash Income (Expense)	3,362	756
(Increase) decrease in accounts receivable and other current assets	(5,374)	30,687
Increase (decrease) in accounts payable and accrued liabilities	24,557	(24,504)
Increase (Decrease) in Income Taxes Payable	(465)	(300)
Increase (decrease) in accrued interest	(1,343)	(441)
Net Cash Provided by (Used in) Operating Activities	189,685	99,695
Cash Flows from Investing Activities:
Additions to property and equipment	(80,225)	(111,285)
Acquisition of oil and gas properties	11,821	(1,090)
Proceeds from the sale of property and equipment	5,730	0
Net Cash Provided by (Used in) Investing Activities	(62,674)	(112,375)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	128,000	121,000
Payments of bank borrowings	(254,000)	(104,000)
Purchase of treasury shares	(534)	(2,945)
Net Cash Provided by (Used in) Financing Activities	(126,534)	14,055
Net increase (decrease) in Cash, Cash Equivalents and Restricted Cash	477	1,375
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	9,206	2,167
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	34,072	16,434
Changes in capital accounts payable and capital accruals	$ 29,194	$ (3,097)

General Information

General Information	3 Months Ended
	Mar. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Information	(1) General Information SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford and Austin Chalk located in South Texas. Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations in the effort to maximize returns on capital invested. The condensed consolidated financial statements are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The unaudited condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2024
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies Basis of Presentation . The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford 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 condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements. 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 condensed consolidated financial statements. In April 2024, the Company entered into a non-cash exchange agreement with a third party to receive approximately 7,700 net acres and working interest in multiple wells in La Salle and McMullen counties. The Company will transfer approximately 5,100 net acres and working interest in 13 wells in DeWitt, Lavaca and McMullen counties. The exchange is subject to customary purchase price adjustments. Through April 30, 2024, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after March 31, 2024: Oil Derivative Contracts Total Volumes Weighted-Average Price Swap Contracts 2024 Contracts 3Q24 92,000 $ 80.47 4Q24 92,000 $ 80.47 2025 Contracts 1Q25 180,000 $ 76.00 2Q25 182,000 $ 75.18 3Q25 184,000 $ 74.46 4Q25 184,000 $ 73.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2025 Contracts 1Q25 180,000 $ 1.80 2Q25 182,000 $ 1.80 3Q25 184,000 $ 1.80 4Q25 184,000 $ 1.80 Calendar Monthly Roll Differential Swaps 2025 Contracts 1Q25 180,000 $ 0.50 2Q25 182,000 $ 0.50 3Q25 184,000 $ 0.50 4Q25 184,000 $ 0.50 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2025 Contracts 4Q25 920,000 $ 3.50 $ 4.38 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 4Q24 920,000 $ (0.49) 2025 Contracts 1Q25 3,600,000 $ (0.30) 2Q25 3,640,000 $ (0.30) 3Q25 3,680,000 $ (0.30) 4Q25 3,680,000 $ (0.30) There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test (as defined below) impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates used in the assessment of business combinations and asset purchases, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2024 and 2023, such internal costs capitalized totaled $1.1 million and $1.4 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended March 31, 2024 and 2023. The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2024 December 31, 2023 Property and Equipment Proved oil and gas properties $ 3,671,913 $ 3,562,268 Unproved oil and gas properties 30,899 28,375 Furniture, fixtures and other equipment 6,657 6,517 Less – Accumulated depreciation, depletion, amortization & impairment (1,315,364) (1,223,241) Property and Equipment, Net $ 2,394,105 $ 2,373,919 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. There was no ceiling test write-down for either of the three months ended March 31, 2024 and 2023. If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record Ceiling Test write-downs in future periods. Accounts Receivable, Net. We assess the collectability 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 March 31, 2024, December 31, 2023 and December 31, 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 condensed consolidated balance sheets. At March 31, 2024, our “Accounts receivable, net” balance included $92.2 million for oil and gas sales, $14.7 million due from joint interest owners, $2.8 million for severance tax credit receivables and $15.8 million for other receivables. 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 related to the South Texas Acquisition and $14.1 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. Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the three months ended March 31, 2024 and 2023 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $5.4 million and $2.7 million for the three months ended March 31, 2024 and 2023, 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. The Company's effective tax rate was approximately 24% and 22% for the three months ended March 31, 2024 and 2023, respectively. The Company recorded an income tax benefit of $4.8 million for the three months ended March 31, 2024 and an income tax provision of $26.8 million for the three months ended March 31, 2023, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year-to-date income. Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2024 and 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. Revenue Recognition . Substantially all of our revenues are derived from sales of oil, natural gas and natural gas liquids (“NGLs”). Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers. The following table provides information regarding our revenues, including oil and gas sales, by product, reported on the condensed consolidated statements of operations for the three months ended March 31, 2024 and 2023 (in thousands): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Revenues: Oil $ 166,704 $ 74,655 Natural gas 53,123 52,922 NGLs 36,218 12,377 Marketing 635 — Total $ 256,680 $ 139,954 Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2024 December 31, 2023 Trade accounts payable $ 52,924 $ 32,225 Accrued operating expenses 26,183 23,104 Accrued compensation costs 7,281 10,208 Asset retirement obligations – current portion 1,597 1,576 Accrued non-income based taxes 10,447 3,870 Accrued corporate and legal fees 119 208 WTI contingency payouts - current portion 26,759 14,282 Payable for settled derivatives 2,828 967 Other payables (1) 15,546 12,376 Total accounts payable and accrued liabilities $ 143,684 $ 98,816 (1) At March 31, 2024 and December 31, 2023 included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our South Texas Acquisition. Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts. The Company did not have any cash equivalents at March 31, 2024 and December 31, 2023. Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. 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): March 31, 2024 December 31, 2023 Cash and cash equivalents $ 1,446 $ 969 Current restricted cash (1) 2,200 2,200 Long-term restricted cash (2) 5,560 5,560 Total cash, cash equivalents and restricted cash $ 9,206 $ 8,729 (1) Current restricted cash is included in “Other Current Assets on the accompanying condensed consolidated balance sheets. (2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets. Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the three months ended March 31, 2024, we purchased 17,949 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. For the three months ended March 31, 2023, we purchased 126,240 treasury shares to satisfy withholding tax obligations arising upon the vesting of restricted shares. New Accounting Pronouncements . 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. 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 reportable 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.

Leases Leases (Notes)

Leases Leases (Notes)	3 Months Ended
	Mar. 31, 2024
Leases [Abstract]
Lessee, Operating Leases	(3) Leases The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2024, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying condensed consolidated balance sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term. As of March 31, 2024, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of March 31, 2024 2024 (Remaining) $ 7,077 2025 7,987 2026 2,968 2027 1,997 2028 1,402 Thereafter 2,710 Total undiscounted lease payments 24,141 Present value adjustment (3,421) Net operating lease liabilities $ 20,720

Share-Based Compensation

Share-Based Compensation	3 Months Ended
	Mar. 31, 2024
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation	(4) Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting. The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.8 million and $1.1 million for the three months ended March 31, 2024 and 2023, respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended March 31, 2024 and 2023. We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards. The Company accounts for forfeitures in compensation cost when they occur. Stock Option Awards The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one five At March 31, 2024, we had no unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the three months ended March 31, 2024: Shares Wtd. Avg. Exer. Price Wtd. Avg. Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands) Options outstanding, beginning of period 196,162 $ 26.46 3.4 $ 525 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 3.1 $ 1,506 Options exercisable, end of period 196,162 $ 26.46 3.1 $ 1,506 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 restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one As of March 31, 2024, we had $10.4 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 2.2 years. The following table provides information regarding RSU activity for the three months ended March 31, 2024: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 285,163 $ 24.61 RSUs granted 233,168 $ 31.08 RSUs forfeited (4,683) $ 29.08 RSUs vested (112,147) $ 23.57 RSUs outstanding, end of period 401,501 $ 28.60 Performance-Based Stock Units On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two On February 23, 2022, the Company granted 122,111 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared 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 on an absolute and relative basis compared 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 On February 21, 2024, the Company granted 132,930 PSUs for which the number of shares earned is based on the TSR of the Company's common stock on an absolute and relative basis compared to the TSR of its selected peers during the performance period from January 1, 2024 to December 31, 2026. 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 $34.99 per unit or 124.74% 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 March 27, 2024, the Company granted 23,103 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, 2024 to December 31, 2026. 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 $46.18 per unit or 133.11% 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 March 31, 2024, we had $9.0 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 2.2 years. The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2024: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 242,860 $ 33.84 Performance based stock units granted 156,033 $ 36.65 Performance based stock units outstanding, end of period 398,893 $ 34.94

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2024
Earnings Per Share [Abstract]
Earnings Per Share	(5) Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2024 and 2023 are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (15,528) 25,445 $ (0.61) $ 94,492 22,440 $ 4.21 Dilutive Securities: Performance Based Stock Unit Awards — 97 RSU Awards — 91 Stock Option Awards — 6 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (15,528) 25,445 $ (0.61) $ 94,492 22,634 $ 4.17 The following is a table of antidilutive options and shares excluded from the computation of Diluted EPS for the periods indicated below (in thousands): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Antidilutive Securities: Stock Option Awards 87 137 Restricted Stock Unit Awards 10 9 Performance Based Stock Unit Awards 60 51

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Long-Term Debt	(6) Long-Term Debt The Company's long-term debt consisted of the following (in thousands): March 31, 2024 December 31, 2023 Credit Facility Borrowings due 2026 (1) $ 596,000 $ 722,000 Second Lien Notes due 2028 500,000 500,000 1,096,000 1,222,000 Unamortized discount on Second Lien Notes due 2028 (7,401) (7,820) Unamortized debt issuance cost on Second Lien Notes due 2028 (11,630) (12,289) Total Debt $ 1,076,969 $ 1,201,891 Less: Current portion of Second Lien Notes due 2028 37,500 28,125 Long-term debt, net $ 1,039,469 $ 1,173,766 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our condensed consolidated balance sheet. As of March 31, 2024 and December 31, 2023, we had $22.7 million and $24.9 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings. Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $596.0 million and $722.0 million as of March 31, 2024 and December 31, 2023, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with the closing of the South Texas Acquisition described further in Note 7, 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 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 March 31, 2024 and December 31, 2023. 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. The Credit Facility matures October 19, 2026, and provides for a maximum credit amount of $2.0 billion, subject to the current borrowing base of $1.2 billion. 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”). The applicable margin 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 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. As of March 31, 2024, the Company's weighted average interest rate on Credit Facility borrowings was 8.42%. 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 March 31, 2024, 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 $18.3 million and $11.9 million for the three months ended March 31, 2024 and 2023, respectively. The amount of commitment fee amortization included in interest expense, net was $0.6 million and $0.3 million for the three months ended March 31, 2024 and 2023, respectively. Senior Secured Second Lien Notes . On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien 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 Notes 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 Notes 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% plus a margin of 6.5%. Additionally, to the extent the Company were to default on the Second Lien Notes, 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 the South Texas Acquisition described further in Note 7. 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 was included within “Interest expense, net” on the condensed 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 in quarterly payments of $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 Notes 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 March 31, 2024, the Company’s interest rate on the Second Lien Notes was 13.08%. As of March 31, 2024, the Company was in compliance with all financial covenants under the Second Lien Notes. The obligations under the Second Lien Notes are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%. As of March 31, 2024, total net amounts recorded for the Second Lien Notes were $481.0 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien Notes totaled $17.7 million and $4.8 million for the three months ended March 31, 2024 and 2023, 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 three months ended March 31, 2024 and 2023 there were no capitalized costs incurred.

Acquisitions and Dispositions A

Acquisitions and Dispositions Acquisitions and Dispostions	3 Months Ended
	Mar. 31, 2024
Discontinued Operations and Disposal Groups [Abstract]
Acquisitions and Dispositions	(7) Acquisitions and Dispositions 2023 South Texas Acquisition On November 30, 2023, SilverBow closed the acquisition of certain oil and gas properties from entities affiliated with Chesapeake Energy Corporation, with consideration comprised of (i) cash paid at the closing of the South Texas Acquisition, (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 South Texas Acquisition 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 three months ended March 31, 2024, the Company recorded losses of $12.8 million related to valuation changes in the 2023 WTI Contingency Payout recorded in “Net gain (loss) on commodity derivatives” on the accompanying condensed 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 South Texas Acquisition as an asset acquisition and allocated the purchase price based on the relative fair value of the assets acquired and liabilities assumed. The South Texas Acquisition 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 $ 583,373 Fair value of contingent consideration 16,933 Deferred acquisition liability 50,000 Total Consideration 650,306 Transaction costs 10,916 Total Cost of Transaction $ 661,222 Allocation of Total Cost Assets Accounts receivable, net $ 1,594 Oil and gas properties 666,360 Right of use assets 187 Total assets 668,141 Liabilities Accounts payable and accrued liabilities 5,275 Lease liability 187 Asset retirement obligations 1,457 Total Liabilities 6,919 Net Assets Acquired $ 661,222

Price-Risk Management Price-Ris

Price-Risk Management Price-Risk Management (Notes)	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities	(8) Price-Risk Management Activities Derivatives are recorded on the condensed consolidated balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps. During the three months ended March 31, 2024 and 2023, the Company recorded losses of $42.7 million and gains of $91.2 million, respectively, on its commodity derivatives. During the three months ended March 31, 2024 and 2023, the Company recorded losses of $13.4 million and gains of $1.0 million, respectively, related to valuation changes on our WTI Contingency Payouts. The Company collected cash payments of $38.4 million and $18.7 million for settled derivative contracts during the three months ended March 31, 2024 and 2023, respectively. At March 31, 2024 and December 31, 2023, there was $13.4 million and $13.5 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in April 2024 and January 2024, respectively. At March 31, 2024 and December 31, 2023, we also had $2.8 million and $1.0 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in April 2024 and January 2024, 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 March 31, 2024, there was $89.5 million and $29.4 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $26.3 million and $8.1 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2023, there was $116.5 million and $55.1 million in current and long-term unsettled derivative assets, respectively, and $5.5 million and $2.5 million in current and long-term unsettled derivative liabilities, respectively. The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $84.5 million net fair value asset at March 31, 2024, and a $163.6 million net fair value asset at December 31, 2023. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of March 31, 2024: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 2Q24 1,209,550 $ 77.40 3Q24 1,239,620 $ 76.42 4Q24 1,222,100 $ 75.97 2025 Contracts 1Q25 846,000 $ 72.32 2Q25 855,400 $ 72.20 3Q25 864,800 $ 72.11 4Q25 772,800 $ 71.82 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 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 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2024 Contracts 2Q24 486,000 $ 1.49 3Q24 552,000 $ 1.49 4Q24 552,000 $ 1.49 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 2Q24 486,000 $ 0.71 3Q24 552,000 $ 0.72 4Q24 552,000 $ 0.72 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 Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 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 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 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 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 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

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2024
Fair Value Disclosures [Abstract]
Fair Value Measurements	(9) Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2023 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, 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 Notes 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 at a relative fair value basis (refer to Note 7 of these Notes to Condensed 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 production from the crude oil and natural gas proved properties, future operating, 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. T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2024 and December 31, 2023, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company’s derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant March 31, 2024 Assets Natural Gas Derivatives $ 109,432 $ — $ 109,432 $ — Natural Gas Basis Derivatives 4,671 — 4,671 — Oil Derivatives 1,070 — 1,070 — Oil Basis Derivatives 39 — 39 — NGL Derivatives 3,755 — 3,755 — Liabilities Natural Gas Derivatives 635 — 635 — Natural Gas Basis Derivatives 2,786 — 2,786 — Oil Derivatives 26,752 — 26,752 — Oil Basis Derivatives 857 — 857 — NGL Derivatives 3,413 — 3,413 — 2023 WTI Contingency Payout 25,439 — 25,439 — 2021 WTI Contingency Payout 1,320 — 1,320 — 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 — Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Notes)	3 Months Ended
	Mar. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(10) Asset Retirement Obligations Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management’s expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2023 and the three months ended March 31, 2024 (in thousands): 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 Accretion expense 316 Liabilities incurred for new wells, acquired wells and facilities construction 34 Asset Retirement Obligations as of March 31, 2024 $ 13,510 At both March 31, 2024 and December 31, 2023, approximately $1.6 million of our asset retirement obligations, respectively, were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies	3 Months Ended
	Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	(11) Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as 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.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2024
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation . The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford 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 condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include: • the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test (as defined below) impairment calculation, • estimates related to the collectability of accounts receivable and the creditworthiness of our customers, • estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf, • estimates of future costs to develop and produce reserves, • accruals related to oil and gas sales, capital expenditures and lease operating expenses, • estimates in the calculation of share-based compensation expense, • estimates of our ownership in properties prior to final division of interest determination, • the estimated future cost and timing of asset retirement obligations, • estimates made in our income tax calculations, including the valuation of our deferred tax assets, • estimates in the calculation of the fair value of commodity derivative assets and liabilities, • estimates in the assessment of current litigation claims against the Company, • estimates used in the assessment of business combinations and asset purchases, • estimates in amounts due with respect to open state regulatory audits, and • estimates on future lease obligations. While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known. We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment	Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2024 and 2023, such internal costs capitalized totaled $1.1 million and $1.4 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. There was no capitalized interest on our unproved properties for both the three months ended March 31, 2024 and 2023. The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2024 December 31, 2023 Property and Equipment Proved oil and gas properties $ 3,671,913 $ 3,562,268 Unproved oil and gas properties 30,899 28,375 Furniture, fixtures and other equipment 6,657 6,517 Less – Accumulated depreciation, depletion, amortization & impairment (1,315,364) (1,223,241) Property and Equipment, Net $ 2,394,105 $ 2,373,919 No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test	Full-Cost Ceiling Test . At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
Accounts Receivable, Net	Accounts Receivable, Net. We assess the collectability 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 March 31, 2024, December 31, 2023 and December 31, 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 condensed 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. The Company's effective tax rate was approximately 24% and 22% for the three months ended March 31, 2024 and 2023, respectively. The Company recorded an income tax benefit of $4.8 million for the three months ended March 31, 2024 and an income tax provision of $26.8 million for the three months ended March 31, 2023, respectively. The tax impact for both periods was a product of the overall forecasted annual effective tax rate applied to the year-to-date income. Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its net operating losses (“NOLs”) if it experiences an ownership change. Generally, an “ownership change” occurs if one or more shareholders, each of whom is deemed to own five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in August 2022 and, therefore, are subject to an annual limitation on the usage of our NOLs generated prior to the ownership change. However, we do not expect to have any of our NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOLs. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 2024 and 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.
Revenue Recognition	Revenue Recognition
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities . The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2024 December 31, 2023 Trade accounts payable $ 52,924 $ 32,225 Accrued operating expenses 26,183 23,104 Accrued compensation costs 7,281 10,208 Asset retirement obligations – current portion 1,597 1,576 Accrued non-income based taxes 10,447 3,870 Accrued corporate and legal fees 119 208 WTI contingency payouts - current portion 26,759 14,282 Payable for settled derivatives 2,828 967 Other payables (1) 15,546 12,376 Total accounts payable and accrued liabilities $ 143,684 $ 98,816 (1) At March 31, 2024 and December 31, 2023 included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our South Texas Acquisition.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy	Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted. The Company maintains cash and cash equivalent balances with major financial institutions, which at times exceed federally insured limits. The Company monitors the financial condition of the financial institutions and has experienced no losses associated with these accounts. The Company did not have any cash equivalents at March 31, 2024 and December 31, 2023. Restricted Cash. Restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations and operational maintenance projects. 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): March 31, 2024 December 31, 2023 Cash and cash equivalents $ 1,446 $ 969 Current restricted cash (1) 2,200 2,200 Long-term restricted cash (2) 5,560 5,560 Total cash, cash equivalents and restricted cash $ 9,206 $ 8,729 (1) Current restricted cash is included in “Other Current Assets on the accompanying condensed consolidated balance sheets. (2) Long-term restricted cash is included in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.
Treasury Stock	Treasury Stock.

Leases Leases (Policies)

Leases Leases (Policies)	3 Months Ended
	Mar. 31, 2024
Leases [Abstract]
Lessee, Leases [Policy Text Block]	Leases The Company follows the FASB's Accounting Standards Codification Topic No. 842 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the condensed consolidated balance sheets. We have elected to not account for lease and non-lease components separately. The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of March 31, 2024, all of the Company’s leases were operating leases. The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying condensed consolidated balance sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. The Company recognizes lease expense on a straight-line basis over the lease term.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation (Policies)	3 Months Ended
	Mar. 31, 2024
Share-Based Payment Arrangement [Abstract]
Share-based Compensation, Option and Incentive Plans Policy	Share-Based Compensation Share-Based Compensation Plans In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016.

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Policies)	3 Months Ended
	Mar. 31, 2024
Earnings Per Share [Abstract]
Earnings Per Share, Policy	Earnings Per Share Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three months ended March 31, 2024 and 2023 are discussed below.

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Policies)	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Debt Issuance Costs, Policy	Debt Issuance Costs

Price-Risk Management Price-R_2

Price-Risk Management Price-Risk Management (Policies)	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Price-Risk Management Activities, Policy	Price-Risk Management Activities Derivatives are recorded on the condensed consolidated balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Disclosures (Policies)	3 Months Ended
	Mar. 31, 2024
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments, Policy	Fair Value Measurements Fair Value on a Recurring Basis . Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien Notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model. The fair value of the current and long-term 2021 WTI Contingency Payout and 2023 WTI Contingency Payout, included within “Accounts payable and accrued liabilities” and “Other long-term liabilities” on the condensed consolidated balance sheets, respectively, 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 Notes 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 at a relative fair value basis (refer to Note 7 of these Notes to Condensed 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 production from the crude oil and natural gas proved properties, future operating, 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)	3 Months Ended
	Mar. 31, 2024
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 condensed consolidated balance sheets.

Commitments and Contingencies_2

Commitments and Contingencies Commitments and Contingencies (Policies)	3 Months Ended
	Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies, Policy	Commitments and Contingencies In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2024
Accounting Policies [Abstract]
Schedule of Subsequent Events	Subsequent Events . We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements. In April 2024, the Company entered into a non-cash exchange agreement with a third party to receive approximately 7,700 net acres and working interest in multiple wells in La Salle and McMullen counties. The Company will transfer approximately 5,100 net acres and working interest in 13 wells in DeWitt, Lavaca and McMullen counties. The exchange is subject to customary purchase price adjustments. Through April 30, 2024, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after March 31, 2024: Oil Derivative Contracts Total Volumes Weighted-Average Price Swap Contracts 2024 Contracts 3Q24 92,000 $ 80.47 4Q24 92,000 $ 80.47 2025 Contracts 1Q25 180,000 $ 76.00 2Q25 182,000 $ 75.18 3Q25 184,000 $ 74.46 4Q25 184,000 $ 73.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2025 Contracts 1Q25 180,000 $ 1.80 2Q25 182,000 $ 1.80 3Q25 184,000 $ 1.80 4Q25 184,000 $ 1.80 Calendar Monthly Roll Differential Swaps 2025 Contracts 1Q25 180,000 $ 0.50 2Q25 182,000 $ 0.50 3Q25 184,000 $ 0.50 4Q25 184,000 $ 0.50 Natural Gas Derivative Contracts Total Volumes Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Collar Contracts 2025 Contracts 4Q25 920,000 $ 3.50 $ 4.38 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 4Q24 920,000 $ (0.49) 2025 Contracts 1Q25 3,600,000 $ (0.30) 2Q25 3,640,000 $ (0.30) 3Q25 3,680,000 $ (0.30) 4Q25 3,680,000 $ (0.30) There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Property and Equipment	The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands): March 31, 2024 December 31, 2023 Property and Equipment Proved oil and gas properties $ 3,671,913 $ 3,562,268 Unproved oil and gas properties 30,899 28,375 Furniture, fixtures and other equipment 6,657 6,517 Less – Accumulated depreciation, depletion, amortization & impairment (1,315,364) (1,223,241) Property and Equipment, Net $ 2,394,105 $ 2,373,919
Disaggregation of Revenue	The following table provides information regarding our revenues, including oil and gas sales, by product, reported on the condensed consolidated statements of operations for the three months ended March 31, 2024 and 2023 (in thousands): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Revenues: Oil $ 166,704 $ 74,655 Natural gas 53,123 52,922 NGLs 36,218 12,377 Marketing 635 — Total $ 256,680 $ 139,954
Accounts Payable and Accrued Liabilities	The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands): March 31, 2024 December 31, 2023 Trade accounts payable $ 52,924 $ 32,225 Accrued operating expenses 26,183 23,104 Accrued compensation costs 7,281 10,208 Asset retirement obligations – current portion 1,597 1,576 Accrued non-income based taxes 10,447 3,870 Accrued corporate and legal fees 119 208 WTI contingency payouts - current portion 26,759 14,282 Payable for settled derivatives 2,828 967 Other payables (1) 15,546 12,376 Total accounts payable and accrued liabilities $ 143,684 $ 98,816 (1) At March 31, 2024 and December 31, 2023 included in Other Payables is $7.8 million in payables related to advances from joint interest owners in connection with our South Texas Acquisition.
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): March 31, 2024 December 31, 2023 Cash and cash equivalents $ 1,446 $ 969 Current restricted cash (1) 2,200 2,200 Long-term restricted cash (2) 5,560 5,560 Total cash, cash equivalents and restricted cash $ 9,206 $ 8,729 (1) Current restricted cash is included in “Other Current Assets on the accompanying condensed consolidated balance sheets.

Leases Leases (Tables)

Leases Leases (Tables)	3 Months Ended
	Mar. 31, 2024
Leases [Abstract]
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	As of March 31, 2024, the Company's future cash payment obligation for its operating lease liabilities are as follows (in thousands): As of March 31, 2024 2024 (Remaining) $ 7,077 2025 7,987 2026 2,968 2027 1,997 2028 1,402 Thereafter 2,710 Total undiscounted lease payments 24,141 Present value adjustment (3,421) Net operating lease liabilities $ 20,720

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2024
Share-Based Payment Arrangement [Abstract]
Stock option activity	The following table provides information regarding stock option award activity for the three months ended March 31, 2024: Shares Wtd. Avg. Exer. Price Wtd. Avg. Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands) Options outstanding, beginning of period 196,162 $ 26.46 3.4 $ 525 Options granted — $ — Options exercised — $ — Options outstanding, end of period 196,162 $ 26.46 3.1 $ 1,506 Options exercisable, end of period 196,162 $ 26.46 3.1 $ 1,506
Restricted stock activity	The following table provides information regarding RSU activity for the three months ended March 31, 2024: RSUs Wtd. Avg. Grant Price RSUs outstanding, beginning of period 285,163 $ 24.61 RSUs granted 233,168 $ 31.08 RSUs forfeited (4,683) $ 29.08 RSUs vested (112,147) $ 23.57 RSUs outstanding, end of period 401,501 $ 28.60
Performance-Based Stock Units Activity	The following table provides information regarding performance-based stock unit activity for the three months ended March 31, 2024: PSUs Wtd. Avg. Grant Price Performance based stock units outstanding, beginning of period 242,860 $ 33.84 Performance based stock units granted 156,033 $ 36.65 Performance based stock units outstanding, end of period 398,893 $ 34.94

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2024
Earnings Per Share [Abstract]
Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS	The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Net Income (Loss) Shares Per Share Net Income (Loss) Shares Per Share Basic EPS: Net Income (Loss) and Share Amounts $ (15,528) 25,445 $ (0.61) $ 94,492 22,440 $ 4.21 Dilutive Securities: Performance Based Stock Unit Awards — 97 RSU Awards — 91 Stock Option Awards — 6 Diluted EPS: Net Income (Loss) and Assumed Share Conversions $ (15,528) 25,445 $ (0.61) $ 94,492 22,634 $ 4.17
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): Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 Antidilutive Securities: Stock Option Awards 87 137 Restricted Stock Unit Awards 10 9 Performance Based Stock Unit Awards 60 51

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The Company's long-term debt consisted of the following (in thousands): March 31, 2024 December 31, 2023 Credit Facility Borrowings due 2026 (1) $ 596,000 $ 722,000 Second Lien Notes due 2028 500,000 500,000 1,096,000 1,222,000 Unamortized discount on Second Lien Notes due 2028 (7,401) (7,820) Unamortized debt issuance cost on Second Lien Notes due 2028 (11,630) (12,289) Total Debt $ 1,076,969 $ 1,201,891 Less: Current portion of Second Lien Notes due 2028 37,500 28,125 Long-term debt, net $ 1,039,469 $ 1,173,766 (1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “ Other Long-Term Assets ” in our condensed consolidated balance sheet. As of March 31, 2024 and December 31, 2023, we had $22.7 million and $24.9 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.

Business Combinations and Asset

Business Combinations and Asset Acquisitions (Tables)	May 10, 2022
Business Combination, Asset Acquisition, and Joint Venture Formation [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 $ 583,373 Fair value of contingent consideration 16,933 Deferred acquisition liability 50,000 Total Consideration 650,306 Transaction costs 10,916 Total Cost of Transaction $ 661,222 Allocation of Total Cost Assets Accounts receivable, net $ 1,594 Oil and gas properties 666,360 Right of use assets 187 Total assets 668,141 Liabilities Accounts payable and accrued liabilities 5,275 Lease liability 187 Asset retirement obligations 1,457 Total Liabilities 6,919 Net Assets Acquired $ 661,222

Price-Risk Management Price-R_3

Price-Risk Management Price-Risk Management (Tables)	3 Months Ended
	Mar. 31, 2024
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 March 31, 2024: Oil Derivative Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 2Q24 1,209,550 $ 77.40 3Q24 1,239,620 $ 76.42 4Q24 1,222,100 $ 75.97 2025 Contracts 1Q25 846,000 $ 72.32 2Q25 855,400 $ 72.20 3Q25 864,800 $ 72.11 4Q25 772,800 $ 71.82 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 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 2Q24 7,757 $ 45.00 $ 57.50 $ 67.85 Oil Basis Swaps Total Volumes Weighted-Average Price 2024 Contracts 2Q24 486,000 $ 1.49 3Q24 552,000 $ 1.49 4Q24 552,000 $ 1.49 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 2Q24 486,000 $ 0.71 3Q24 552,000 $ 0.72 4Q24 552,000 $ 0.72 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 Contracts Total Volumes Weighted-Average Price Weighted-Average Collar Sub Floor Price Weighted-Average Collar Floor Price Weighted-Average Collar Call Price Swap Contracts 2024 Contracts 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 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 2Q24 188,000 $ 2.00 $ 2.50 $ 3.37 Natural Gas Basis Derivative Swaps Total Volumes Weighted-Average Price 2024 Contracts 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 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

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2024
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	T he following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of March 31, 2024 and December 31, 2023, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company’s derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements. Fair Value Measurements at (in thousands) Total Quoted Prices in Significant Other Significant March 31, 2024 Assets Natural Gas Derivatives $ 109,432 $ — $ 109,432 $ — Natural Gas Basis Derivatives 4,671 — 4,671 — Oil Derivatives 1,070 — 1,070 — Oil Basis Derivatives 39 — 39 — NGL Derivatives 3,755 — 3,755 — Liabilities Natural Gas Derivatives 635 — 635 — Natural Gas Basis Derivatives 2,786 — 2,786 — Oil Derivatives 26,752 — 26,752 — Oil Basis Derivatives 857 — 857 — NGL Derivatives 3,413 — 3,413 — 2023 WTI Contingency Payout 25,439 — 25,439 — 2021 WTI Contingency Payout 1,320 — 1,320 — 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 —

Asset Retirement Obligations _3

Asset Retirement Obligations Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Roll-forward of our asset retirement obligations	The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2023 and the three months ended March 31, 2024 (in thousands): 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 Accretion expense 316 Liabilities incurred for new wells, acquired wells and facilities construction 34 Asset Retirement Obligations as of March 31, 2024 $ 13,510

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2024 USD ($) bbl MMBTU $ / MMBTU $ / Boe	Mar. 31, 2023 USD ($)	Apr. 30, 2024 MMBTU bbl $ / Boe $ / MMBTU	Dec. 31, 2023 USD ($)
Property and Equipment
Proved oil and gas properties | $	$ 3,671,913			$ 3,562,268
Unproved oil and gas properties | $	30,899			28,375
Furniture, fixtures, and other equipment | $	6,657			6,517
Less - Accumulated depreciation, depletion, and amortization | $	(1,315,364)			(1,223,241)
Net Furniture, Fixtures and other equipment | $	2,394,105			2,373,919
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	256,680	$ 139,954
Accounts Payable and Accrued Liabilities
Trade accounts payable | $	52,924			32,225
Accrued operating expenses | $	26,183			23,104
Accrued compensation costs | $	7,281			10,208
Asset retirement obligation - current portion | $	1,597			1,576
Accrued non-income based taxes | $	10,447			3,870
Accrued corporate and legal fees | $	119			208
WTI contingency payouts - current portion | $	26,759			14,282
Payables for Settled Derivatives | $	2,828			967
Other payables | $	15,546			12,376
Total Accounts payable and accrued liabilities | $	143,684			$ 98,816
Oil sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	166,704	74,655
Natural gas sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	53,123	52,922
NGL sales [Member]
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	36,218	12,377
Marketing Sales
Disaggregation of Revenue [Line Items]
Oil and gas sales | $	$ 635	$ 0
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,239,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.42
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			92,000
Derivative, Swap Type, Fixed Price | $ / Boe			80.47
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	3.71
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,222,100
Derivative, Swap Type, Fixed Price | $ / Boe	75.97
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			92,000
Derivative, Swap Type, Fixed Price | $ / Boe			80.47
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	4.04
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	846,000
Derivative, Swap Type, Fixed Price | $ / Boe	72.32
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			76
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,950,000
Derivative, Swap Type, Fixed Price	4.25
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	855,400
Derivative, Swap Type, Fixed Price | $ / Boe	72.20
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			75.18
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,105,000
Derivative, Swap Type, Fixed Price	3.72
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	864,800
Derivative, Swap Type, Fixed Price | $ / Boe	72.11
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			74.46
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	3.86
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	772,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.82
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			73.85
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,590,000
Derivative, Swap Type, Fixed Price	4.15
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.25)
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.28)
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Swap Type, Fixed Price			(0.49)
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,200,000
Derivative, Swap Type, Fixed Price	(0.09)
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			3,600,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,280,000
Derivative, Swap Type, Fixed Price	(0.26)
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			3,640,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.23)
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			3,680,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.26)
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			3,680,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63.50
Derivative, Average Cap Price	75.53
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [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 Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63
Derivative, Average Cap Price	75.35
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [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 Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	238,500
Derivative, Average Floor Price	64
Derivative, Average Cap Price	74.62
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [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 Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	227,500
Derivative, Average Floor Price	60.80
Derivative, Average Cap Price	72.22
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Derivative Instruments and Hedging Activities Disclosures [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 Swaps
Derivative Instruments and Hedging Activities Disclosures [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 Swaps
Derivative Instruments and Hedging Activities Disclosures [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] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			3.50
Derivative, Average Cap Price			4.38

Summary of Significant Accoun_5

Summary of Significant Accounting Policies (Details Textual) $ in Thousands	3 Months Ended
	Mar. 31, 2024 USD ($) bbl MMBTU $ / MMBTU $ / Boe shares	Mar. 31, 2023 USD ($) shares	Apr. 30, 2024 MMBTU bbl $ / Boe $ / MMBTU	Apr. 12, 2024	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Sep. 20, 2022
Summary of Significant Accounting Policies
Stockholders Rights Agreement, Percentage of Common Stock Threshold							0.15
Capitalized Costs Oil and Gas Producing Activities | $	$ 1,100	$ 1,400
Proved oil and gas properties | $	3,671,913				$ 3,562,268
Unproved oil and gas properties | $	30,899				28,375
Furniture, fixtures, and other equipment | $	6,657				6,517
Less - Accumulated depreciation, depletion, and amortization | $	(1,315,364)				(1,223,241)
Net Furniture, Fixtures and other equipment | $	$ 2,394,105				2,373,919
Discount rate for estimated future net revenues from proved properties	10%
Write-down of oil and gas properties | $	$ 0	0
Allowance for doubtful accounts receivable, current | $	100				100	$ 100
Accounts receivable, gross | $	92,200				91,900	70,900
Accounts receivable related to joint interest owners | $	14,700				7,000	5,600
Severance tax receivable | $	2,800				7,200	4,300
Other receivables | $	$ 15,800				14,100	8,900
Percentage of working interest in wells	100%
Total amount of supervision fees charged to wells | $	$ 5,400	$ 2,700
Effective Income Tax Rate Reconciliation, Percent	24%	22%
Provision (Benefit) for Income Taxes | $	$ (4,787)	$ 26,812
Oil and gas sales | $	256,680	139,954
Trade accounts payable | $	52,924				32,225
Accrued operating expenses | $	26,183				23,104
Accrued payroll costs | $	7,281				10,208
Asset retirement obligation - current portion | $	1,597				1,576
Accrued non-income based taxes | $	10,447				3,870
Accrued corporate and legal fees | $	119				208
WTI contingency payouts - current portion | $	26,759				14,282
Payables for Settled Derivatives | $	2,828				967
Other payables | $	15,546				12,376
Accounts payable and accrued liabilities | $	143,684				98,816
Payable for Joint Interest Owner Advance | $	7,800				7,800
Cash and Cash Equivalents, at Carrying Value | $	1,446				969
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | $	$ 9,206	$ 2,167			8,729	$ 792
Purchase of treasury stock (shares) | shares	17,949	126,240
Operational Maintenance Project
Summary of Significant Accounting Policies
Escrow Deposit | $	$ 2,200				2,200
Plugging and Abandonment Project
Summary of Significant Accounting Policies
Escrow Deposit | $	5,560				5,560
Chesapeake South Texas Acquisition
Summary of Significant Accounting Policies
Account Receivable for purchase price adjustments | $					$ 18,100
Oil sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	166,704	$ 74,655
Natural gas sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	53,123	52,922
NGL sales [Member]
Summary of Significant Accounting Policies
Oil and gas sales | $	36,218	12,377
Marketing Sales
Summary of Significant Accounting Policies
Oil and gas sales | $	$ 635	$ 0
Subsequent Event [Member]
Summary of Significant Accounting Policies
Net acres acquired				7,700
Net acres transferred				5,100
Wells transferred				13
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	1,239,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.42
Swap [Member] | Third Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			92,000
Derivative, Swap Type, Fixed Price | $ / Boe			80.47
Swap [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	3.71
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	1,222,100
Derivative, Swap Type, Fixed Price | $ / Boe	75.97
Swap [Member] | Fourth Quarter 2024 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			92,000
Derivative, Swap Type, Fixed Price | $ / Boe			80.47
Swap [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	4.04
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	846,000
Derivative, Swap Type, Fixed Price | $ / Boe	72.32
Swap [Member] | First Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			76
Swap [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	13,950,000
Derivative, Swap Type, Fixed Price	4.25
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	855,400
Derivative, Swap Type, Fixed Price | $ / Boe	72.20
Swap [Member] | Second Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			75.18
Swap [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	14,105,000
Derivative, Swap Type, Fixed Price	3.72
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	864,800
Derivative, Swap Type, Fixed Price | $ / Boe	72.11
Swap [Member] | Third Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			74.46
Swap [Member] | Third Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	3.86
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	772,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.82
Swap [Member] | Fourth Quarter 2025 | Oil Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			73.85
Swap [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	10,590,000
Derivative, Swap Type, Fixed Price	4.15
Basis Swap [Member] | Third Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.25)
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Third Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.28)
Basis Swap [Member] | Fourth Quarter 2024 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Swap Type, Fixed Price			(0.49)
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Fourth Quarter 2024 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,200,000
Derivative, Swap Type, Fixed Price	(0.09)
Basis Swap [Member] | First Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			3,600,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | First Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | First Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			180,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,280,000
Derivative, Swap Type, Fixed Price	(0.26)
Basis Swap [Member] | Second Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			3,640,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Second Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			182,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.23)
Basis Swap [Member] | Third Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			3,680,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Third Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.26)
Basis Swap [Member] | Fourth Quarter 2025 | Natural Gas Basis Derivative Swaps [Member] | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			3,680,000
Derivative, Swap Type, Fixed Price			(0.30)
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Derivative | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			1.80
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Fourth Quarter 2025 | Oil Basis Calendar Monthly Roll Differential Swap | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | bbl			184,000
Derivative, Swap Type, Fixed Price | $ / Boe			0.50
Collar Contracts [Member] | Third Quarter 2024 | Oil Derivative Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63.50
Derivative, Average Cap Price	75.53
Collar Contracts [Member] | Third Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
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 Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63
Derivative, Average Cap Price	75.35
Collar Contracts [Member] | Fourth Quarter 2024 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
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 Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	238,500
Derivative, Average Floor Price	64
Derivative, Average Cap Price	74.62
Collar Contracts [Member] | First Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
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 Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	227,500
Derivative, Average Floor Price	60.80
Derivative, Average Cap Price	72.22
Collar Contracts [Member] | Second Quarter 2025 | Natural Gas Derivative Swaps
Summary of Significant Accounting Policies
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 Swaps
Summary of Significant Accounting Policies
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 Swaps
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Average Floor Price	3.75
Derivative, Average Cap Price	4.65
Collar Contracts [Member] | Fourth Quarter 2025 | Natural Gas Derivative Swaps | Subsequent Event [Member]
Summary of Significant Accounting Policies
Oil and Gas Production Hedged Volumes | MMBTU			920,000
Derivative, Average Floor Price			3.50
Derivative, Average Cap Price			4.38
Minimum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property	2 years
Maximum [Member]
Summary of Significant Accounting Policies
Estimated useful lives of property	20 years

Leases Leases (Details)

Leases Leases (Details) $ in Thousands	Mar. 31, 2024 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 7,077
Lessee, Operating Lease, Liability, Payments, Due Year Two	7,987
Lessee, Operating Lease, Liability, Payments, Due Year Three	2,968
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,997
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,402
Lessee, Operating Lease, Liability, Payments, Due after Year Five	2,710
Lessee, Operating Lease, Liability, Payments, Due	24,141
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(3,421)
Operating Lease, Liability	$ 20,720

Share-Based Compensation (Detai

Share-Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands										3 Months Ended
	Mar. 31, 2024	Mar. 27, 2024	Feb. 21, 2024	Dec. 31, 2023	Sep. 30, 2023	Feb. 23, 2023	Feb. 22, 2023	Feb. 23, 2022	Feb. 24, 2021	Mar. 31, 2024	Mar. 31, 2023
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense										$ 1,830	$ 1,124
Share-based compensation (capitalized)										100	100
General and Administrative Expense [Member]
Share-based Compensation (Details Textual)
Share-based Payment Arrangement, Noncash Expense										1,800	$ 1,100
Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 0									0
Remaining contract life of outstanding stock options.	3 years 1 month 6 days			3 years 4 months 24 days
Stock option award outstanding aggregate intrinsic value	$ 1,506			$ 525						1,506
Remaining contract life of exercisable stock option	3 years 1 month 6 days
Stock option award exercisable aggregate intrinsic value										$ 1,506
Stock Option Activity
Options outstanding, beginning of period, shares	196,162			196,162						196,162
Options outstanding, beginning of period, weighted average price	$ 26.46			$ 26.46						$ 26.46
Options, Grants in Period										0
Options, Grants in Period, Weighted Average Grant Date Fair Value										$ 0
Options, Exercises in Period										0
Options, Exercises in Period, Weighted Average Exercise Price										$ 0
Options exercisable, end of period, shares	196,162									196,162
Options exercisable, end of period, weighted average price	$ 26.46									$ 26.46
Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 10,400									$ 10,400
Unrecognized compensation expense weighted-average period										2 years 2 months 12 days
Restricted stock activity
Restricted shares outstanding, beginning of period, shares										285,163
Restricted shares outstanding, beginning of period, weighted average price										$ 24.61
Restricted shares granted, shares										233,168
Restricted shares granted, weighted average price										$ 31.08
Restricted shares forfeited										(4,683)
Restricted shares forfeited, weighted average price										$ 29.08
Restricted shares vested, shares										(112,147)
Restricted shares vested, weighted average price										$ 23.57
Restricted shares outstanding, end of period, shares	401,501			285,163						401,501
Restricted shares outstanding, end of period, weighted average price	$ 28.60			$ 24.61						$ 28.60
Performance Shares [Member]
Share-based Compensation (Details Textual)
Stock option award unrecognized compensation	$ 9,000									$ 9,000
Unrecognized compensation expense weighted-average period					2 years 2 months 12 days
Share-based Compensation, Expected Term		3 years	3 years			3 years		3 years	2 years
Restricted stock activity
Restricted shares outstanding, beginning of period, shares										242,860
Restricted shares outstanding, beginning of period, weighted average price										$ 33.84
Restricted shares granted, shares		23,103	132,930			120,749		122,111	161,389	156,033
Restricted shares granted, weighted average price		$ 46.18	$ 34.99			$ 31.18		$ 36.47	$ 13.13	$ 36.65
Restricted shares vested, shares							(303,410)
Restricted shares outstanding, end of period, shares	398,893			242,860						398,893
Restricted shares outstanding, end of period, weighted average price	$ 34.94			$ 33.84						$ 34.94
Percent of payout for performance based stock units	100%	133.11%	124.74%			136.28%		150.93%	157.60%	100%
Approved payout for performance based stock units							188%
Minimum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										1 year
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										1 year
Minimum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		0%	0%			0%		0%	0%
Maximum [Member] | Share-based Payment Arrangement, Option [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										5 years
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation (Details Textual)
Stock option award vesting period										5 years
Maximum [Member] | Performance Shares [Member]
Restricted stock activity
Percent of payout for performance based stock units		200%	200%			200%		200%	200%

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Basic EPS:
Net Income (Loss)	$ (15,528)	$ 94,492
Income, share amounts	25,445	22,440
Earnings Per Share, Basic	$ (0.61)	$ 4.21
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ (15,528)	$ 94,492
Weighted Average Shares Outstanding - Diluted	25,445	22,634
Earnings Per Share, Diluted	$ (0.61)	$ 4.17
Performance Shares [Member]
Dilutive Securities:
Dilutive Securities	0	97
Diluted EPS:
Antidilutive shares excluded from EPS, shares	60	51
Restricted Stock Units (RSUs) [Member]
Dilutive Securities:
Dilutive Securities	0	91
Diluted EPS:
Antidilutive shares excluded from EPS, shares	10	9
Share-based Payment Arrangement, Option [Member]
Dilutive Securities:
Dilutive Securities	0	6
Diluted EPS:
Antidilutive shares excluded from EPS, shares	87	137

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands					3 Months Ended		12 Months Ended
	Nov. 30, 2023 USD ($)	Jun. 14, 2023	Nov. 29, 2021 USD ($)	Nov. 12, 2021 USD ($)	Mar. 31, 2024 USD ($)	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Sep. 30, 2023 USD ($)	Dec. 15, 2017 USD ($)
Bank Borrowings
Long-term Debt, excluding current maturities					$ 1,039,469		$ 1,173,766
Second Lien [Abstract]
Long-term debt, gross					$ 1,096,000		1,222,000
Discount Rate for Estimated Future Net Revenues from Proved Properties					10%
Long-term debt, net					$ 1,076,969		1,201,891
Long-Term Debt, Current Maturities					37,500		28,125
Gross interest expense including amortization of debt issuance costs					36,017	$ 16,745
Credit Facility [Member]
Bank Borrowings
Debt Issuance Costs, Net					22,700		24,900
Credit Facility [Member] | Line of Credit [Member]
Bank Borrowings
Long-term Debt, excluding current maturities					$ 596,000		722,000
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,000,000
Line of Credit Facility, Current Borrowing Capacity	1,200,000							$ 775,000
Line of Credit, Letters of Credit Issuable	25,000
Line of Credit Facility, Increase (Decrease), Net	$ 425,000
Commitment fee basis points for the credit facility	0.50%
Line of Credit, Additional Interest Due to Payment Default	2%
Debt, Weighted Average Interest Rate					8.42%
Line of Credit, Required Security Interest on Oil and Gas Properties	85%
Line of Credit, Covenant, Debt to EBITDA Ratio	3
Line of Credit, Covenant, Current Ratio, Minimum	1
Line of Credit Facility, Commitment Fee Amount					$ 600	300
Payments of Debt Issuance Costs	$ 20,000				0
Second Lien [Abstract]
Gross interest expense including amortization of debt issuance costs					18,300	11,900
Credit Facility [Member] | Minimum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Line of Credit [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0175
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0275
Credit Facility [Member] | Maximum [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate | Line of Credit [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	0.0275
Debt Instrument Escalating Rates for Eurodollar Rate Loans	0.0375
Second Lien Notes [Member]
Bank Borrowings
Debt Issuance Costs, Net					11,630		12,289
Long-term Debt, excluding current maturities	$ 500,000				500,000		500,000		$ 198,000
Second Lien [Abstract]
Incremental 2nd Lien Notes	350,000
Long-term debt, gross				$ 150,000					200,000
Debt Instrument, Unamortized Discount	$ (7,000)				$ (7,401)		(7,820)		$ (2,000)
Repayments of Long-Term Debt			$ 50,000
Second Lien, Required Security Interest on Proved Reserves	85%			90%
Debt Instrument, Interest Rate, Stated Percentage					13.08%
Second Lien, Required Security Interest on Oil and Gas Properties	85%
Discount Rate for Estimated Future Net Revenues for Proved Properties at 9%	9%
Second Lien, Asset Coverage Ratio, Minimum	1.10
Long-term debt, net					$ 481,000
Long-Term Debt, Current Maturities					37,500		28,125
Gross interest expense including amortization of debt issuance costs					$ 17,700	$ 4,800
Incremental 2nd Lien Notes, Net	$ 343,000
Write off of Debt Issuance Cost							200
Discount, Writeoff							100
Professional Fees							$ 10,600
Second Lien, Total Debt to EBITDA Ratio, Maximum	3
Second Lien, Reduction in Total Debt to EBITDA Ratio	0.25
Second Lien, Asset Coverage Ratio, after March 31, 2024	1.25
Second Lien, Current Ratio, Minimum	1
Quarterly Note Repayment Requirement	$ 9,400
Second Lien, Covenant, Total Indebtedness to EBITDA	2.25
Second Lien Notes [Member] | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Second Lien [Abstract]
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 [Abstract]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Second Lien Notes [Member] | Alternative Base Interest Rate [Member]
Second Lien [Abstract]
Debt Instrument, Minimum Margin on SOFR		1%
Debt Instrument, Basis Spread on Variable Rate		6.50%

Acquisitions and Dispositions_2

Acquisitions and Dispositions Acquisitions and Dispositions (Details) $ in Thousands		3 Months Ended
	Nov. 30, 2023 USD ($)	Mar. 31, 2024 USD ($)	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on WTI Contingency Payout		$ (13,400)	$ 1,000
Deferred acquisition liability		50,000		$ 50,000
Right of Use Assets		20,658		12,888
Operating Lease, Liability		20,720
Asset Retirement Obligations, Noncurrent		11,913		$ 11,584
Chesapeake South Texas Acquisition
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
WTI Annual Earn Out, Average Monthly Settlement Price 2024, Over $80	80
2024 WTI Annual Earnout Payment, if WTI over $80	$ 50,000
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
2024 WTI Annual Earnout Payment, if WTI over $75 and less than $80	$ 25,000
WTI Annual Earn Out, Average Monthly Settlement Price in 2024, Below $75	75
Gain (Loss) on WTI Contingency Payout		$ 12,800
Acquisition of oil and gas properties	$ 583,373
2023 WTI Contingency Payout	16,933
Deferred acquisition liability	50,000
Asset Acquisition, Consideration Transferred	650,306
Asset Acquisition, Transaction Costs	10,916
Asset Acquisition, Total Cost of Transaction	661,222
Accounts Receivables, Net	1,594
Allocation of Total Cost, Oil and gas properties	666,360
Right of Use Assets	187
Allocation of Total cost, Total assets	668,141
Accounts Payable and Accrued Liabilities, Current	5,275
Operating Lease, Liability	187
Asset Retirement Obligations, Noncurrent	1,457
Allocation of Total Cost, Total Liabilities	$ 6,919

Price-Risk Management Price-R_4

Price-Risk Management Price-Risk Management (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2024 USD ($) bbl MMBTU $ / MMBTU $ / Boe	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Price Risk Derivatives, Net | $	$ (42,700)	$ 91,200
Gain (Loss) on WTI Contingency Payout | $	(13,400)	1,000
Cash Received (Paid) On Settlements of Derivative Contracts | $	38,371	$ 18,699
Receivables for Settled Derivatives | $	13,400		$ 13,500
Payables for Settled Derivatives | $	2,828		967
Derivative, Fair Value, Net | $	84,500		163,600
Other Current Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	89,500		116,500
Other Noncurrent Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset | $	29,400		55,100
Other Current Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	26,300		5,500
Other Noncurrent Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Liability, Fair Value, Gross Liability | $	$ 8,100		$ 2,500
Swap [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,209,550
Derivative, Swap Type, Fixed Price | $ / Boe	77.40
Swap [Member] | Oil Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,239,620
Derivative, Swap Type, Fixed Price | $ / Boe	76.42
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	1,222,100
Derivative, Swap Type, Fixed Price | $ / Boe	75.97
Swap [Member] | Oil Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	846,000
Derivative, Swap Type, Fixed Price | $ / Boe	72.32
Swap [Member] | Oil Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	855,400
Derivative, Swap Type, Fixed Price | $ / Boe	72.20
Swap [Member] | Oil Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	864,800
Derivative, Swap Type, Fixed Price | $ / Boe	72.11
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	772,800
Derivative, Swap Type, Fixed Price | $ / Boe	71.82
Swap [Member] | Oil Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	472,500
Derivative, Swap Type, Fixed Price | $ / Boe	68.94
Swap [Member] | Oil Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	455,000
Derivative, Swap Type, Fixed Price | $ / Boe	68.98
Swap [Member] | Oil Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	432,400
Derivative, Swap Type, Fixed Price | $ / Boe	69.03
Swap [Member] | Oil Derivative Swaps | Fourth Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	386,150
Derivative, Swap Type, Fixed Price | $ / Boe	69.09
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	15,390,000
Derivative, Swap Type, Fixed Price	3.60
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	3.71
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,100,000
Derivative, Swap Type, Fixed Price	4.04
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	13,950,000
Derivative, Swap Type, Fixed Price	4.25
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	14,105,000
Derivative, Swap Type, Fixed Price	3.72
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	3.86
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,590,000
Derivative, Swap Type, Fixed Price	4.15
Swap [Member] | Natural Gas Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,580,000
Derivative, Swap Type, Fixed Price	4.49
Swap [Member] | Natural Gas Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,465,000
Derivative, Swap Type, Fixed Price	3.56
Swap [Member] | Natural Gas Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,580,000
Derivative, Swap Type, Fixed Price	3.74
Swap [Member] | Natural Gas Derivative Swaps | Fourth Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	10,120,000
Derivative, Swap Type, Fixed Price	4.14
Swap [Member] | NGL Derivative | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	491,400
Derivative, Swap Type, Fixed Price	25.92
Swap [Member] | NGL Derivative | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	496,800
Derivative, Swap Type, Fixed Price	25.92
Swap [Member] | NGL Derivative | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	496,800
Derivative, Swap Type, Fixed Price	25.92
Swap [Member] | NGL Derivative | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price	23.88
Swap [Member] | NGL Derivative | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price	23.88
Swap [Member] | NGL Derivative | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price	23.88
Swap [Member] | NGL Derivative | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price	23.88
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	215,000
Derivative, Average Floor Price	61.08
Derivative, Average Cap Price	73.57
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63.50
Derivative, Average Cap Price	75.53
Collar Contracts [Member] | Oil Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	184,000
Derivative, Average Floor Price	63
Derivative, Average Cap Price	75.35
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	238,500
Derivative, Average Floor Price	64
Derivative, Average Cap Price	74.62
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	227,500
Derivative, Average Floor Price	60.80
Derivative, Average Cap Price	72.22
Collar Contracts [Member] | Oil Derivative Swaps | First Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	90,000
Derivative, Average Floor Price	64
Derivative, Average Cap Price	71.50
Collar Contracts [Member] | Oil Derivative Swaps | Second Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	91,000
Derivative, Average Floor Price	64
Derivative, Average Cap Price	71.50
Collar Contracts [Member] | Oil Derivative Swaps | Third Quarter 2026
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	92,000
Derivative, Average Floor Price	64
Derivative, Average Cap Price	71.50
Collar Contracts [Member] | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [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] | Natural Gas Derivative Swaps | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	920,000
Derivative, Average Floor Price	3.75
Derivative, Average Cap Price	4.65
3-Way Collar | Oil Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,757
Derivative, Average Sub Floor Price	45
Derivative, Average Floor Price	57.50
Derivative, Average Cap Price	67.85
3-Way Collar | Natural Gas Derivative Swaps | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	188,000
Derivative, Average Sub Floor Price	2
Derivative, Average Floor Price	2.50
Derivative, Average Cap Price	3.37
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	486,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.49
Basis Swap [Member] | Oil Basis Derivative | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Oil Basis Derivative | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Oil Basis Derivative | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Oil Basis Derivative | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	1.75
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	486,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.71
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	552,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.72
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	360,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	364,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Oil Basis Calendar Monthly Roll Differential Swap | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | bbl	368,000
Derivative, Swap Type, Fixed Price | $ / Boe	0.43
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,380,000
Derivative, Swap Type, Fixed Price	(0.29)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.25)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2024
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	16,560,000
Derivative, Swap Type, Fixed Price	(0.28)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | First Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,200,000
Derivative, Swap Type, Fixed Price	(0.09)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Second Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,280,000
Derivative, Swap Type, Fixed Price	(0.26)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Third Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.23)
Basis Swap [Member] | Natural Gas Basis Derivative Swaps [Member] | Fourth Quarter 2025
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Oil and Gas Production Hedged Volumes | MMBTU	7,360,000
Derivative, Swap Type, Fixed Price	(0.26)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Fair Value, Recurring [Member] - USD ($) $ in Thousands	Mar. 31, 2024	Dec. 31, 2023
Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	$ 109,432	$ 116,410
Derivative Liability	635	641
Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4,671	6,111
Derivative Liability	2,786	2,599
Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1,070	39,940
Derivative Liability	26,752	3,302
2023 WTI Contingency Payout	25,439	12,682
2021 WTI Contingency Payout	1,320	2,310
Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	39	708
Derivative Liability	857	921
NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	3,755	8,494
Derivative Liability	3,413	550
Fair Value, Inputs, Level 1 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2023 WTI Contingency Payout	0	0
2021 WTI Contingency Payout	0	0
Fair Value, Inputs, Level 1 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	109,432	116,410
Derivative Liability	635	641
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	4,671	6,111
Derivative Liability	2,786	2,599
Fair Value, Inputs, Level 2 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	1,070	39,940
Derivative Liability	26,752	3,302
2023 WTI Contingency Payout	25,439	12,682
2021 WTI Contingency Payout	1,320	2,310
Fair Value, Inputs, Level 2 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	39	708
Derivative Liability	857	921
Fair Value, Inputs, Level 2 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	3,755	8,494
Derivative Liability	3,413	550
Fair Value, Inputs, Level 3 [Member] | Natural Gas Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
2023 WTI Contingency Payout	0	0
2021 WTI Contingency Payout	0	0
Fair Value, Inputs, Level 3 [Member] | Oil Basis Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | NGL Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset	0	0
Derivative Liability	$ 0	$ 0

Asset Retirement Obligations _4

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 13,510		$ 13,160	$ 10,456
Accretion expense	316	$ 224	985
Liabilities incurred for new wells and facilities construction	34		1,883
Reductions due to plugged wells and facilities			(718)
Revisions in estimates			554
Asset retirement obligation - current portion	$ 1,597		$ 1,576